SM Energy Company Annual Report 2015

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-Kþ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the fiscal year ended December 31, 2015oro Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934Commission file number 001-31539SM ENERGY COMPANY(Exact name of registrant as specified in its charter)Delaware(State or other jurisdictionof incorporation or organization)41-0518430(I.R.S. Employer Identification No.)1775 Sherman Street, Suite 1200, Denver, Colorado(Address of principal executive offices)80203(Zip Code)(303) 861-8140(Registrant’s telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:Title of each class Name of each exchange on which registeredCommon stock, $.01 par value New York Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No oIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ NooIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit andpost such files). Yesþ NooIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to thebest of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.Large accelerated filer þAccelerated filer oNon-accelerated filer o (Do not check if a smaller reporting company)Smaller reporting company oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þThe aggregate market value of the 66,782,794 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock onJune 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, of $46.12 per share, as reported on the New York Stock Exchange, was$3,080,022,459. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who isotherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for otherpurposes.As of February 17, 2016, the registrant had 68,077,546 shares of common stock outstanding.DOCUMENTS INCORPORATED BY REFERENCECertain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2016annual meeting of stockholders to be filed within 120 days after December 31, 2015.1TABLE OF CONTENTSITEM PAGE PART I ITEMS 1. and 2.BUSINESS and PROPERTIES4 General4 Strategy4 Significant Developments in 20154 Outlook for 20165 Core Operational Areas6 Reserves8 Production13 Productive Wells13 Drilling and Completion Activity14 Acreage15 Delivery Commitments16 Major Customers16 Employees and Office Space17 Title to Properties17 Seasonality17 Competition18 Government Regulations18 Cautionary Information about Forward-Looking Statements22 Available Information24 Glossary of Oil and Gas Terms25ITEM 1A.RISK FACTORS29ITEM 1B.UNRESOLVED STAFF COMMENTS52ITEM 3.LEGAL PROCEEDINGS52ITEM 4.MINE SAFETY DISCLOSURES52 PART II53ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES53ITEM 6.SELECTED FINANCIAL DATA56ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS58 Overview of the Company58 Financial Results of Operations and Additional Comparative Data64 Comparison of Financial Results and Trends between 2015 and 2014 and between 2014 and 201367 Overview of Liquidity and Capital Resources74 Critical Accounting Policies and Estimates81 Accounting Matters83 Environmental84 Non-GAAP Financial Measures852TABLE OF CONTENTS(Continued)ITEM PAGEITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUTMARKET RISK (included within the content of ITEM 7)87ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA88ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURE141ITEM 9A.CONTROLS AND PROCEDURES142ITEM 9B.OTHER INFORMATION145 PART III145ITEM 10.DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATEGOVERNANCE145ITEM 11.EXECUTIVE COMPENSATION145ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIALOWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS145ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,AND DIRECTOR INDEPENDENCE147ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES147 PART IV148ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES1483PART IWhen we use the terms “SM Energy,” “the Company,” “we,” “us,” or “our,” we are referring to SM Energy Company and itssubsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of ourbusiness under Glossary of Oil and Gas Terms. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation ofthese types of statements.ITEMS 1. and 2. BUSINESS and PROPERTIESGeneralWe are an independent energy company engaged in the acquisition, exploration, development, and production of crude oil andcondensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout the document) inonshore North America. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering of common stockwas in December 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol “SM.”Our principal offices are located at 1775 Sherman Street, Suite 1200, Denver, Colorado 80203, and our telephone number is(303) 861-8140.StrategyOur strategic objective is to profitably build our ownership and operatorship of North American oil, gas, and NGL producingassets that have high operating margins and significant opportunities for additional economic investment. We pursue growthopportunities through both exploration and acquisitions, and seek to maximize the value of our assets through industry-leadingtechnology application and outstanding operational execution. We focus on achieving high full-cycle economic returns on ourinvestments and maintaining a simple, strong balance sheet through a conservative approach to leverage.Significant Developments in 2015•Production. We achieved record levels of production for 2015. Our average daily production was composed of 52.7 MBblof oil, 475.7 MMcf of gas, and 44.0 MBbl of NGLs, for an average equivalent production rate of 175.9 MBOE per day,which was an increase of 16 percent from an average of 151.1 MBOE per day in 2014. Please refer to Core OperationalAreas below for additional discussion.•Reserves and Capital Investment. Our estimated proved reserves decreased 14 percent to 471.3 MMBOE at December 31,2015, from 547.7 MMBOE at December 31, 2014, of which 25.4 MMBOE related to the divestiture of proved reserves. Weadded 160.6 MMBOE through drilling activities during the year, led by our activities in the Eagle Ford shale andBakken/Three Forks resource plays. Costs incurred for drilling and exploration activities, excluding acquisitions, decreased34 percent to $1.4 billion in 2015 when compared to 2014. We had strong reserve additions as a result of our success inreducing costs, optimizing completions, and generating better well results in our core development programs; however,these additions were offset by the impact of lower commodity prices. Our proved reserve life decreased to 7.3 years in 2015compared to 9.9 years in 2014. Please refer to Reserves and Core Operational Areas below for additional discussion.•Increased Liquidity. During 2015, we extended the maturity of a portion of our long-term debt by using the proceeds fromour issuance of $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 to redeem the $350.0million principal amount of our 6.625% Senior Notes due 2019. The earliest maturity for any of our Senior Notes occurs in2021. Please refer to Overview of Liquidity4and Capital Resources in Part II, Item 7 of this report for additional discussion on our current and future liquidity.•Divestiture Activity. During 2015, we divested a total of 25.4 MMBOE of proved reserves in multiple transactions foraggregate cash proceeds of approximately $357.9 million. Our most significant divestiture activity was the sale of our Mid-Continent assets in the second quarter of 2015.•Sustained Low Commodity Prices. Our financial condition and results of operations are significantly affected by the priceswe receive for oil, gas, and NGLs, which can fluctuate dramatically.Oil prices continued to decline throughout 2015. The daily NYMEX spot price ranged from a high of $61.43 per Bbl inJune to a low of $34.73 per Bbl in December. Oil prices declined further subsequent to year end 2015, dropping to a 12-year low of $26.21 per Bbl in February 2016. The average NYMEX price decreased to $48.68 per Bbl in 2015 compared to$93.03 per Bbl in 2014.Natural gas prices have been under downward pressure over the past several years due to high levels of supply andremained highly volatile during 2015. The daily NYMEX spot price ranged from a high of $3.29 per MMBtu in January to alow of $1.53 per MMBtu in December. The average NYMEX price decreased in 2015 to $2.61 per MMBtu compared to$4.35 per MMBtu in 2014.NGL prices continued to decrease in 2015 in line with oil price declines. The monthly OPIS NGL price ranged from a highof $22.57 per Bbl in February to a low of $17.07 per Bbl in December. NGL prices declined further subsequent to year end2015, dropping to a low of $14.73 per Bbl in January 2016. The average OPIS price decreased in 2015 to $19.76 per Bblcompared to $38.93 per Bbl in 2014.•Impairments. We recorded impairment of proved properties expense of $468.7 million, abandonment and impairment ofunproved properties expense of $78.6 million, and impairment of other property and equipment expense of $49.4 millionfor the year ended December 31, 2015. These impairments were largely due to commodity price declines, which impactedour Powder River Basin program and certain legacy and non-core assets, as well as our decision to reduce capital investedin the development of our east Texas exploration program in light of the sustained, low commodity price environment.Outlook for 2016Our goal is to maintain a strong balance sheet and preserve liquidity in the current commodity price environment. We expect toincur capital expenditures below adjusted EBITDAX in order to minimize any impact to our total debt. We believe this focus on ourliquidity will best preserve our balance sheet and will give us the flexibility to adapt as industry conditions change.Our capital program for 2016 will be approximately $705 million, of which, approximately 85 percent will be invested indrilling and completion activities, with the focus on our core development programs in the Bakken/Three Forks, Permian Basin, andEagle Ford shale. We plan to continue our focus on conducting safe operations even as we pursue cost saving measures throughout ourbusiness. Please refer to Outlook for 2016 under Part II, Item 7 of this report for additional discussion concerning our capital plans for2016.5Core Operational AreasOur 2015 operations were concentrated in four onshore operating areas in the United States. We divested our Mid-Continentassets during the second quarter of 2015. The following table summarizes estimated proved reserves, PV-10, production, and costsincurred in oil and gas activities for the year ended December 31, 2015, for our core operating areas:South Texas &Gulf Coast RockyMountain Permian Mid-Continent (2) Total (1)Proved Reserves Oil (MMBbl)43.6 88.2 13.4 — 145.3Gas (Bcf)1,116.9 102.9 44.2 — 1,264.0NGLs (MMBbl)112.6 2.8 — — 115.4MMBOE (1)342.4 108.1 20.8 — 471.3Relative percentage73% 23% 4% —% 100%Proved Developed %50% 57% 49% —% 52%PV-10 (in millions) (3) Proved Developed$793.4 $667.3 $132.3 $— $1,593.0Proved Undeveloped52.1 129.3 16.1 — 197.5Total Proved$845.5 $796.6 $148.4 $— $1,790.5Relative percentage47% 45% 8% —% 100%Production Oil (MMBbl)7.9 9.5 1.8 — 19.2Gas (Bcf)149.5 9.3 5.1 9.7 173.6NGLs (MMBbl)15.7 0.3 — — 16.1MMBOE (1)48.5 11.3 2.7 1.7 64.2Avg. Daily Equivalents(MBOE/d)132.9 31.1 7.4 4.6 175.9Relative percentage75% 18%4% 3% 100%Costs Incurred (in millions)(4)$765.3 $538.5 $59.4 $9.0 $1,395.0____________________________________________(1)Totals may not sum or calculate due to rounding.(2)We divested our Mid-Continent assets in the second quarter of 2015.(3)The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report. Areconciliation between PV-10 and the after tax amount is shown in the Reserves section below.(4)Amounts do not sum to total costs incurred due to certain costs relating to our new venture projects being excluded from the regional table above.In general, we reduced our capital spending activity across all regions during 2015 in light of the low commodity priceenvironment. We had strong proved reserve additions and positive performance revisions for the year ended December 31, 2015,especially in our Eagle Ford shale and Bakken/Three Forks resource plays; however, our total estimated proved reserves decreasedfrom year-end 2014 due to the divestiture of our Mid-Continent assets, a significant negative price revision, and the removal of provedundeveloped reserves related to changes in our development plan.South Texas & Gulf Coast Region. Operations in our South Texas & Gulf Coast region are managed from our office inHouston, Texas. Within this region, we have both operated and non-operated Eagle Ford shale programs on approximately 197,000 netacres. Our operated program accounts for approximately 80 percent of our total Eagle Ford acreage and production. Our acreageposition covers a significant portion of the western Eagle Ford shale play, including acreage in the oil/condensate, NGL-rich gas, anddry gas windows of the play. Our development program has shifted to utilizing longer laterals and completions with higher sandloadings, which is6resulting in improved well performance as shown in our positive performance revision to our proved reserves for the year endedDecember 31, 2015.A significant portion of our 2015 capital was deployed in our South Texas & Gulf Coast region in our operated and outside-operated Eagle Ford shale programs. We incurred $765.3 million of costs to add approximately 119.3 MMBOE of estimated provedreserves through our drilling activities. As of December 31, 2015, we had 76 gross and net wells that had been drilled but notcompleted in our operated Eagle Ford shale program. Production for 2015 increased 21 percent over 2014 to 48.5 MMBOE. Estimatedproved reserves decreased 13 percent at year-end 2015 to 342.4 MMBOE from 394.6 MMBOE at year-end 2014.Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in Billings, Montana. We haveapproximately 162,000 net acres being actively developed in the Bakken and Three Forks formations. During 2015, we focused ontesting completion optimizations and down-spacing in Divide County, North Dakota.In the Powder River Basin, we have approximately 204,000 net acres, a large portion of which are prospective for the Frontierand Shannon intervals. Given the current commodity price environment, we have reduced our activity in the Powder River Basin.We incurred $538.5 million of costs to add approximately 34.6 MMBOE of estimated proved reserves in our Rocky Mountainregion through our drilling activities. As of December 31, 2015, we had 48 gross (40 net) drilled but not completed wells in ouroperated Bakken/Three Forks program. Production for 2015 increased 30 percent over 2014 to 11.3 MMBOE. Estimated provedreserves slightly decreased to 108.1 MMBOE at year-end 2015 from 108.4 MMBOE at year-end 2014.Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our Permian region coverswestern Texas and southeastern New Mexico. As of December 31, 2015, we had approximately 23,000 net acres in our Permian region,a large portion of which is held by production. We began 2015 with one operated drilling rig and dropped this rig during the secondquarter of 2015.Costs incurred in our Permian region decreased to $59.4 million in 2015 compared to $195.4 million in 2014. Estimated provedreserves increased four percent to 20.8 MMBOE at year-end 2015 from 20.0 MMBOE at year-end 2014. Production decreased threepercent to 2.7 MMBOE in 2015 from 2.8 MMBOE in 2014.Mid-Continent Region. During the second quarter of 2015, we divested our Mid-Continent assets located in the Arkoma Basinof Oklahoma and Arklatex area of east Texas and northern Louisiana. We also closed our regional office in Tulsa, Oklahoma in mid-2015.7ReservesThe table below presents summary information with respect to the estimates of our proved reserves for each of the years in thethree-year period ended December 31, 2015. We engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit at least 80 percent of ourtotal calculated proved reserve PV-10 for each year presented. The prices used in the calculation of proved reserve estimates reflect the12-month average of the first-day-of-the-month prices in accordance with Securities and Exchange Commission (“SEC”) rules, andwere $50.28 per Bbl for oil, $2.59 per MMBtu for natural gas, and $20.20 per Bbl for NGLs for the year ended December 31, 2015.We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecisethan reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new informationbecomes available. PV-10 shown in the following table is not intended to represent the current market value of our estimated provedreserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. Noestimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC,since the beginning of the last fiscal year. The following table should be read along with the section entitled Risk Factors – RisksRelated to Our Business below.Our ability to replace our production is critical to us. Please refer to the reserve replacement term in the Glossary of Oil and GasTerms section of this report for information describing how this metric is calculated.8The following table summarizes estimated proved reserves, PV-10, and standardized measure of discounted future cash flows asof December 31, 2015, 2014, and 2013: As of December 31, 2015 2014 2013Reserve data: Proved developed Oil (MMBbl)75.6 89.3 70.2 Gas (Bcf)644.4 784.6 569.2 NGLs (MMBbl)61.5 66.7 43.8 MMBOE (1)244.5 286.8 208.9Proved undeveloped Oil (MMBbl)69.6 80.4 56.3 Gas (Bcf)619.7 682.0 620.1 NGLs (MMBbl)53.9 66.8 60.2 MMBOE (1)226.8 260.9 219.9Total Proved (1) Oil (MMBbl) (1)145.3 169.7 126.6 Gas (Bcf) (1)(2)1,264.0 1,466.5 1,189.3 NGLs (MMBbl) (1)115.4 133.5 103.9 MMBOE (1)471.3 547.7 428.7Proved developed reserves %52% 52% 49%Proved undeveloped reserves %48% 48% 51% Reserve data (in millions): Proved developed PV-10$1,593.0 $5,253.0 $3,898.6Proved undeveloped PV-10197.5 2,363.9 1,629.9Total proved PV-10$1,790.5 $7,616.9 $5,528.5Standardized measure of discounted future net cashflows$1,868.9 $5,698.8 $4,009.4 Reserve life (years)7.3 9.9 8.9(1) Totals may not sum or calculate due to rounding. (2) As of December 31, 2015, proved gas reserves contain 48.1 Bcf of gas that we expect to produce and use as field fuel(primarily for compressors). 9The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the pre-tax PV-10 (Non-GAAP) of total proved reserves. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 in theGlossary of Oil and Gas Terms section of this report below. As of December 31, 2015 2014 2013 (in millions)Standardized measure of discounted future net cashflows$1,868.9 $5,698.8 $4,009.4Add: 10 percent annual discount, net of income taxes1,228.7 3,407.2 2,500.6Add: future undiscounted income taxes— 3,511.4 2,722.2Undiscounted future net cash flows3,097.6 12,617.4 9,232.2Less: 10 percent annual discount without tax effect(1,307.1) (5,000.5) (3,703.7)PV-10$1,790.5 $7,616.9 $5,528.5Proved Undeveloped ReservesProved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage orfrom existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified asproved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled orwhere reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as havingproved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within fiveyears, unless specific circumstances justify a longer time period. As of December 31, 2015, 2.8 MMBOE of proved undevelopedreserves have been on our books in excess of five years. These reserves are associated with three wells that were drilled in 2015 and arescheduled to be completed and producing in 2016.For locations that are more than one location removed from developed producing locations, we utilized reliable geologic andengineering technology to add approximately 76.4 MMBOE of proved undeveloped reserves in the more developed portions of ourEagle Ford shale position, 5.1 MMBOE of proved undeveloped reserves in the more developed portions of our Bakken/Three Forksshale position, and 0.4 MMBOE of proved undeveloped reserves in the more developed portion of our Wolfcamp shale position in thePermian Basin. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formationand their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (bothvertically and horizontally collected), and petrophysical analysis of the log data, mud logs, gas sample analysis, measurements of totalorganic content, thermal maturity, test production, fluid properties, and core data as well as significant statistical performance datayielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areaswhere both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonablycertain results. In all other areas, we restricted proved undeveloped locations to immediate offsets to producing wells.10As of December 31, 2015, we had 226.8 MMBOE of proved undeveloped reserves, which is a decrease of 34.1 MMBOE, or 13percent, from 260.9 MMBOE at December 31, 2014. The following table provides a reconciliation of our proved undeveloped reservesfor the year ended December 31, 2015: Total(MMBOE)Total proved undeveloped reserves: Beginning of year260.9Revisions of previous estimates (1)(35.4)Additions from discoveries, extensions, and infill (2)119.6Sales of reserves(4.3)Purchases of minerals in place0.9Removed for five-year rule (3)(79.4)Conversions to proved developed (4)(35.5)End of year226.8____________________________________________(1)Revisions of previous estimates primarily relate to a negative price revision of 57.0 MMBOE due to the decline in commodity prices during 2015. Thenegative price revision was partially offset by positive performance revisions totaling 21.6 MMBOE primarily in our Eagle Ford shale and Bakken/ThreeForks resource plays due to improved performance related to enhanced completions and reductions in operating expenses, which extended the economiclives of the wells.(2)We added 98.6 MMBOE of infill proved undeveloped reserves primarily in our Eagle Ford shale and Bakken/Three Forks resource plays, as well as anadditional 21.0 MMBOE of proved undeveloped reserves through extensions and discoveries, primarily in our Eagle Ford shale play.(3)Proved undeveloped reserves were reduced by 79.4 MMBOE due to changes in our development plan, which caused these locations to be reclassifiedprimarily 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 implemented during 2015.(4)Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks resourceplays. During 2015, we incurred approximately $415 million on projects associated with reserves booked as proved undeveloped reserves at the end of2014. Our 2015 track record and development pace were both below 20 percent. This was due to delineation and testing of an incremental landing zonein our Eagle Ford shale asset, delineation and testing of the Bakken interval, step-out drilling on acreage acquired late in 2014 in our Divide County,North Dakota position, and due to the large reserve volumes associated with drilled and uncompleted wells at year-end 2015. At December 31, 2015,drilled but uncompleted wells represent 59.2 MMBOE of total proved undeveloped reserves. Our multi-year historical track is in excess of 20 percent.As of December 31, 2015, estimated future development costs relating to our proved undeveloped reserves are approximately$478 million, $344 million, and $465 million in 2016, 2017, and 2018, respectively.Internal Controls Over Proved Reserves EstimatesOur internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reservequantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves isdelegated to our corporate reserves group, which is managed by our Engineering Manager - Corporate Reserves, subject to theoversight of our management and the Audit Committee of our Board of Directors, as discussed below. Our Engineering Manager -Corporate Reserves has over 15 years of experience in the energy industry, and holds a Bachelor of Science degree in ChemicalEngineering with a Petroleum Certificate from the University of Alabama. She is also a member of the Society of Petroleum Engineers.Technical, geological, and engineering reviews of our assets are performed throughout the year by our regional staff. This data, inconjunction with economic data and our ownership information, is used in making a determination of estimated proved reservequantities. Our regional engineering technical staff do not report directly to our Engineering Manager - Corporate Reserves; they reportto either their respective regional technical managers11or directly to the regional manager. This design is intended to promote objective and independent analysis within our regions in theproved reserves estimation process.Third-party Reserves AuditRyder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data weprovided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the provedreserve amounts of our audited properties determined by Ryder Scott are required to be within 10 percent of our proved reserveamounts for the total company, as well as for each respective region. Ryder Scott is an independent petroleum engineering consultingfirm that has been providing petroleum engineering consulting services throughout the world for over 70 years. The technical person atRyder Scott primarily responsible for overseeing our reserves audit is an Advising Senior Vice President who received a Bachelor ofScience Degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineeringfrom the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas, a member of theSociety of Petroleum Engineers, and the Society of Petroleum Evaluation Engineers. The Ryder Scott 2015 report concerning ourreserves is included as Exhibit 99.1.In addition to a third party audit, our reserves are reviewed by our management with the Audit Committee of our Board ofDirectors. Management, which includes our President and Chief Executive Officer, Executive Vice President and Chief FinancialOfficer, and Executive Vice President - Operations, is responsible for reviewing and verifying that the estimate of proved reserves isreasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with RyderScott’s results and also meets with Ryder Scott representatives from time to time to discuss processes and findings.12ProductionThe following table summarizes the volumes and realized prices of oil, gas, and NGLs produced and sold from properties inwhich we held an interest during the periods indicated. Realized prices presented below exclude the effects of derivative contractsettlements. Also presented is a summary of related production costs per BOE. For the Years Ended December 31, 2015 2014 2013Net production Oil (MMBbl)19.2 16.7 13.9Gas (Bcf)173.6 152.9 149.3NGLs (MMBbl)16.1 13.0 9.5MMBOE (2)64.2 55.1 48.3Eagle Ford net production (1) Oil (MMBbl)7.6 6.9 5.1Gas (Bcf)147.2 120.6 97.1NGLs (MMBbl)15.6 12.7 9.2MMBOE (2)47.7 39.7 30.5Realized price Oil (per Bbl)$41.49 $80.97 $91.19Gas (per Mcf)$2.57 $4.58 $3.93NGLs (per Bbl)$15.92 $33.34 $35.95Per BOE$23.36 $45.01 $45.50Production costs per BOE Lease operating expense$3.73 $4.28 $4.49Transportation costs$6.02 $6.11 $5.34Production taxes$1.13 $2.13 $2.19Ad valorem tax expense$0.39 $0.46 $0.33____________________________________________(1)In each of the years 2015, 2014, and 2013, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our totalproved reserves expressed on an equivalent basis.(2)Amounts may not calculate due to rounding.Productive WellsAs of December 31, 2015, we had working interests in 1,459 gross (872 net) productive oil wells and 1,772 gross (653 net)productive gas wells. Productive wells are either wells producing in commercial quantities or wells mechanically capable of commercialproduction, but are temporarily shut-in. Multiple completions in the same wellbore are counted as one well. A well is categorized understate reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but suchdesignation may not be indicative of current production.13Drilling and Completion ActivityAll of our drilling and completion activities are conducted by independent contractors. We do not own any drilling orcompletion equipment. The following table summarizes the number of operated and outside-operated wells drilled and completed orrecompleted on our properties in 2015, 2014, and 2013, excluding non-consented projects, active injector wells, salt water disposalwells, and any wells in which we own only a royalty interest: For the Years Ended December 31, 2015 2014 2013 Gross Net Gross Net Gross NetDevelopment wells: Oil87 56.5 133 66.1 154 75.4Gas272 100.8 476 165.5 443 162.5Non-productive— — 8 5.3 10 8.5 359 157.3 617 236.9 607 246.4Exploratory wells: Oil5 3.5 5 3.0 6 5.1Gas1 1.0 7 4.8 4 2.4Non-productive5 4.1 4 3.3 1 0.3 11 8.6 16 11.1 11 7.8Total370 165.9 633 248.0 618 254.2A productive well is an exploratory, development, or extension well that is producing or capable of commercial production ofoil, gas, and/or NGLs. A non-productive well, frequently referred to within the industry as a dry hole, is an exploratory, development,or extension well that proves to be incapable of producing oil, gas, and/or NGLs in commercial quantities to justify completion, or uponcompletion, the economic operation of a well.As defined by the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previouslyfound to be productive of oil or gas in another reservoir. A development well is a well drilled within the proved area of an oil or naturalgas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wellscompleted at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation ofequipment for production of oil, gas, and/or NGLs, or in the case of a dry well, the reporting to the appropriate authority that the wellhas been plugged and abandoned.In addition to the wells drilled and completed in 2015 (included in the table above), as of January 31, 2016, we wereparticipating in the drilling of 33 gross wells. We operate 9 of these wells on a gross basis (7.5 on a net basis) and other companiesoperate the remaining 24 gross wells (4 on a net basis). With respect to completion activity, at such date, there were 364 gross wells inwhich we have an interest that were being completed or waiting on completion. We operate 143 of these wells on a gross basis (134 ona net basis) and were participating in 221 gross (38 on a net basis) outside-operated wells. 14AcreageThe following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, andmineral servitudes that we hold as of December 31, 2015. Undeveloped acreage includes leasehold interests containing provedundeveloped reserves. Developed Acres (1) Undeveloped Acres (2) Total Gross Net Gross Net Gross NetSouth Texas & Gulf Coast: Operated Eagle Ford68,773 66,027 98,178 95,447 166,951 161,474Outside-operated Eagle Ford137,348 24,089 100,015 11,869 237,363 35,958Other22,083 8,649 204,647 163,988 226,730 172,637Rocky Mountain: North Rockies: Divide144,542 90,639 41,450 26,647 185,992 117,286Raven48,693 30,466 5,136 1,163 53,829 31,629Bear Den21,763 11,233 4,937 1,555 26,700 12,788Stateline MT21,102 16,289 12,740 6,718 33,842 23,007Other74,921 51,400 298,599 208,365 373,520 259,765South Rockies: PRB Cretaceous75,035 52,726 193,815 151,655 268,850 204,381Other1,556 1,472 126,212 102,642 127,768 104,114Permian: Sweetie Peck13,228 13,177 521 521 13,749 13,698Other12,439 7,534 1,831 1,457 14,270 8,991Other10,499 10,499 22,604 17,583 33,103 28,082Total (3)651,982 384,200 1,110,685 789,610 1,762,667 1,173,810____________________________________________(1)Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage thatincludes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included onlyas 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 quantitiesof 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 144,100, 85,300, and 26,700 net acres are scheduled to expire by December 31, 2016, 2017, and 2018,respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases. Our east Texas acreage,which has been impaired as of December 31, 2015, represents more than 50 percent of the net acres scheduled to expire over the next three years.15Delivery CommitmentsAs of December 31, 2015, we had gathering, processing, and transportation throughput commitments with various parties thatrequire us to deliver fixed, determinable quantities of production over specified time frames. We have an aggregate minimumcommitment to deliver 2,277 Bcf of natural gas and 36 MMBbl of oil through 2028, of which the first 1,059 Bcf of natural gasdelivered under a certain agreement does not have a deficiency payment. We are required to make periodic deficiency payments forany shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume commitment for natural gas isprojected, we have rights under certain contracts to arrange for third party gas to be delivered, and such volume will count toward ourminimum volume commitment. Our current production is insufficient to offset these aggregate contractual liabilities, but we expect tofulfill the delivery commitments with production from the future development of our proved undeveloped reserves and from the futuredevelopment of resources not yet characterized as proved reserves or through arranging for the delivery of third party gas. In the eventthat no product is delivered in accordance with these agreements, the aggregate undiscounted deficiency payments would beapproximately $864.0 million as of December 31, 2015.Subsequent to December 31, 2015, we entered into amendments to oil and gas gathering agreements related to certain of ourEagle Ford shale assets, neither of which previously had a minimum volume commitment, in order to obtain more favorable rates andterms. Under these amendments, we are now committed to deliver 310 Bcf of natural gas and 41 MMBbl of oil through 2034. In theevent that we deliver no product, the aggregate undiscounted deficiency payments under these amended agreements would beapproximately $360.8 million. Subsequent to December 31, 2015, we also entered into an amendment to a gas gathering agreementrelated to certain other Eagle Ford shale assets, which reduced our volume commitment amount as of December 31, 2015, by 829 Bcfand the aggregate undiscounted deficiency payments by $118.2 million. As a result of these subsequent amendments, the aggregateundiscounted deficiency payments as of December 31, 2015, would have been approximately $1.1 billion.As of the filing date of this report, we do not expect any material shortfalls.Major CustomersWe do not believe the loss of any single purchaser of our crude oil, natural gas, and NGLs would materially impact ouroperating results, as these are products with well-established markets and numerous purchasers are present in our operating regions.During 2015 and 2014, we had one major customer that represented approximately 21 percent and 19 percent, respectively, of our totalproduction revenue, which is discussed in the next paragraph. In 2015 and 2014, we also sold to four entities that are under commonownership. In aggregate, these four entities represented approximately 10 percent and 14 percent of our total production revenue in2015 and 2014, respectively; however, none of these entities individually represented more than 10 percent of our production revenue.Additionally, in 2015 we sold to three entities that are under common ownership, which in aggregate represented 11 percent of our totalproduction revenue; however, none of these entities individually represented more than 10 percent of our production revenue. During2013, we had three major customers that represented approximately 26 percent, 16 percent, and 12 percent, respectively, of our totalproduction revenue.During the third quarter of 2013, we entered into various marketing agreements with a joint venture partner, whereby we aresubject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Whileour joint venture partner is the first purchaser under these contracts, representing 21 percent and 19 percent of our total productionrevenue in 2015 and 2014, respectively, we also share with it the risk of non-performance by its counterparty purchasers and haveincluded this joint venture partner as a major customer in the discussion above. Several of the joint venture partner’s counterpartypurchasers under these contracts are also direct purchasers of our production from other areas.16Employees and Office SpaceAs of February 17, 2016, we had 786 full-time employees. This is an approximate 12 percent decrease from the 896 reportedfull-time employees as of February 18, 2015. None of our employees are subject to a collective bargaining agreement, and we considerour relations with our employees to be good.The following table summarizes the approximate square footage of office space leased by us, as of December 31, 2015,including our corporate headquarters and regional offices:Region Approximate SquareFootage LeasedCorporate 108,000South Texas & Gulf Coast 64,000Rocky Mountain 44,000Permian 54,000Mid-Continent (1) 50,000Total 320,000____________________________________________(1)During the third quarter of 2015, we vacated our office space in Tulsa, Oklahoma. We have subleased this space through 2019 and our lease expires in2022.In addition to the leased office space in the table above, we own a total of 72,000 square feet of office space.Title to PropertiesSubstantially all of our interests are held pursuant to oil and gas leases from third parties. A title opinion is usually obtained priorto the commencement of initial drilling operations. We have obtained title opinions or have conducted other title review on substantiallyall of our producing properties and believe we have satisfactory title to such properties in accordance with standards generally acceptedin the oil and gas industry. Most of our producing properties are subject to mortgages securing indebtedness under our credit facility,royalty and overriding royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the useof, or affect the value of, such properties. We typically perform only minimal title investigation before acquiring undeveloped leaseholdacreage.SeasonalityGenerally, but not always, the demand and price levels for natural gas increase during winter months and decrease duringsummer months. To lessen the impact of seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrialusers utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer.However, increased summertime demand for electricity can divert gas that traditionally is placed into storage. This could reduce thetypical seasonal price differential. Demand for oil and heating oil is also generally higher in the winter and the summer driving season,although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimeslessen these fluctuations. Recently, the impact of seasonality on oil has been somewhat muted by overall supply and demandeconomics attributable to worldwide production in excess of existing worldwide demand for oil. Certain of our drilling, completion, andother operations are also subject to seasonal limitations. Seasonal weather conditions, government regulations and lease stipulationsadversely affect our ability to conduct drilling activities in some of the areas where we operate. See Risk Factors - Risks Related to OurBusiness below for additional discussion.17CompetitionThe oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gasproperties. We believe our acreage position provides a foundation for development activities that we expect to fuel our future growth.Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. Webelieve the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financialresources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our coreoperating areas. However, we face intense competition from a substantial number of major and independent oil and gas companies,which in some cases have larger technical staffs and greater financial and operational resources than we do. Many of these companiesnot only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have gathering,processing or refining operations, market refined products, own drilling rigs or other equipment, or generate electricity.We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for thedrilling, completion, and maintenance of wells, as well as for the gathering, transporting and processing of crude oil, natural gas andNGLs. Consequently, we may face shortages, delays or increased costs in securing these services from time to time. The oil and gasindustry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied naturalgas. Competitive conditions may be affected by future energy, climate-related, financial, or other policies, legislation, and regulations.In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals.Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the availability ofindividuals with these skills is becoming more limited due to the evolving demographics of our industry. We are not insulated from thecompetition for quality people, and we must compete effectively in order to be successful.Government RegulationsOur business is extensively controlled by numerous federal, state, and local laws and governmental regulations. These laws andregulations may be changed from time to time in response to economic or political conditions, or other developments, and ourregulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business andconsequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent thanothers in our industry.Energy Regulations. Many of the states in which we conduct our operations have adopted laws and regulations governing theexploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells,imposing bond requirements in order to drill or operate wells, and governing the timing of drilling and location of wells, the method ofdrilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonmentof wells. Our operations are also subject to various state conservation laws and regulations, including regulations governing the size ofdrilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitizationor pooling of oil and gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil andgas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fairapportionment of production from fields and individual wells.Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of LandManagement (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and ordersthat are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLMbefore drilling and must comply with regulations governing, among other things, engineering and construction specifications forproduction facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the postingof bonds18to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federalleases.Our sales of natural gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal EnergyRegulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce.FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation ofnatural gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus canindirectly affect the sales prices we receive for natural gas production.Environmental, Health and Safety Matters General. Our operations are subject to stringent and complex federal, state, tribal and local laws and regulations governingprotection of the environment and worker health and safety as well as the discharge of materials into the environment. These laws andregulations may, among other things:•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 connectionwith 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 areascontaining 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 pluggingabandoned wells. These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwisebe possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry andconsequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may resultin more stringent permitting, waste handling, disposal, and cleanup requirements for the oil and natural gas industry and could have asignificant impact on our operating costs.The following is a summary of some of the existing laws, rules and regulations to which our business is subject.Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate thegeneration, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of theUnited States Environmental Protection Agency (the “EPA”), individual states administer some or all of the provisions of RCRA,sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastesassociated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardouswaste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage anddispose of wastes, which could have a material adverse effect on our results of operations and financial position.Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response,Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard tofault or legality of conduct, on classes of persons who are considered to19be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the sitewhere the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. UnderCERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that havebeen released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is notuncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substancesreleased into the environment.We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and productionfor many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at thetime, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or onor under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of ourproperties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardoussubstances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them maybe subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposedsubstances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws imposerestrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, intowaters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with theterms of a permit issued by the EPA, U.S. Army Corps of Engineers or analogous state agencies. Federal and state regulatory agenciescan impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CleanWater Act and analogous state laws and regulations.The Oil Pollution Act of 1990 (“OPA”) addresses prevention, containment and cleanup, and liability associated with oilpollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability forcontainment and removal costs, natural resource damages and certain other consequences of oil spills into jurisdictional waters. Anyunpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutantsthrough air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continuesto develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agenciescan impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAAand associated state laws and regulations.Climate change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhousegases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA,contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adoptingand implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA.Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and the demand for oiland gas. See Risk Factors - Risks Related to Our Business - Legislative and regulatory initiatives related to global warming and climatechange could have an adverse effect on our operations and the demand for crude oil, natural gas and NGLs. In addition to the effectsof regulation, the meteorological effects of global climate change could pose additional risks to our operations, including physicaldamage risks associated with more frequent, more intensive storms and flooding, and could adversely affect the demand for ourproducts.20Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have anadverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are knownto exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species,and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nestingseasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could ordera complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protectedspecies. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair ourability to timely complete well drilling and development and could adversely affect our future production from those areas.National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to theNational Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate majoragency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will preparean environmental assessment to determine the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary,will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of ourcurrent exploration and production activities, as well as proposed exploration and development plans, on federal lands requiregovernmental permits subject to the requirements of NEPA. This process has the potential to delay development of some of our oil andnatural gas projects.OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act(“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulationsunder Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materialsused or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established avariety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are insubstantial compliance with the applicable requirements of OSHA and comparable laws.Hydraulic fracturing. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbonsfrom tight formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. Theprocess involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock andstimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has assertedfederal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (the “SDWA”)Underground Injection Control Program. The federal SDWA protects the quality of the nation’s public drinking water through theadoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-groundformations that may adversely affect drinking water sources.Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gasactivities using hydraulic fracturing techniques, which could potentially cause a decrease in the completion of new oil and gas wells,increased compliance costs, and delays, all of which could adversely affect our financial position, results of operations and cash flows.As new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costlyfor us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at thefederal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities couldbecome subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs.Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from ourreserves.We believe it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricterstandards. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our currentoperations and that our continued compliance with existing requirements will21not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will notbe adversely affected in the future.Environmental, Health and Safety Initiatives. We are committed to conducting our business in a manner that protects theenvironment and the health and safety of our employees, contractors and the public. We set annual goals for our environmental, healthand safety program focused on reducing the number of safety related incidents that occur and the number and impact of spills ofproduced fluids. We also periodically conduct regulatory compliance audits of our operations to ensure our compliance with allregulations and provide appropriate training for our employees. Reducing air emissions as a result of leaks, venting, or flaring of naturalgas during operations has become a major focus area for regulatory efforts and for our compliance efforts. While flaring is sometimesnecessary, releases of natural gas to the environment and flaring is an economic waste and reducing these volumes is a priority for us.To avoid flaring where possible, we restrict testing periods and make every effort to ensure that our production is connected to gaspipeline infrastructure as quickly as possible after well completions. We have cooperated with other producers in North Dakota in theongoing development of recommendations to reduce the amount of flaring that is occurring there as a result of area wide infrastructurelimitations that are beyond our control. Another focus for our environmental effort has been reduction of water use through recyclingof flowback water in south Texas for use as frac fluid. We have incurred in the past, and expect to incur in the future, capital costsrelated to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.Cautionary Information about Forward-Looking StatementsThis Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statementsof historical facts, included in this Form 10-K that address activities, events, or developments with respect to our financial condition,results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that addressplans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,”“believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended toidentify forward-looking statements. Forward-looking statements appear throughout this Form 10-K, and include statements about suchmatters as:•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capitalexpenditures;•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 acquisitions;•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 revenuesassociated with those proved 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 ofoperations or to defer capital investment, and our outlook on our future financial condition or results of operations; and22•other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition andResults of Operations section in Item 7 of this Form 10-K.Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and ourperception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriateunder the circumstances. These statements are subject to a number of known and unknown risks and uncertainties, which may causeour actual results and performance to be materially different from any future results or performance expressed or implied by theforward-looking statements. Some of these risks are described in the Risk Factors section of this Form 10-K, and include such factorsas:•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 have an interest may be defective;•the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontaldrilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reservesor production;•the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactionswith respect to certain assets, including whether such transactions will be consummated or completed in the form or timingand 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 NGLsales;•the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;•our ability to deliver necessary quantities of natural gas or crude oil to contractual counterparties;23•price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;•the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;•the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable toadverse economic conditions, and make it more difficult for us to make payments on our debt;•the possibility that covenants in our debt agreements may limit our discretion in the operation of our business, prohibit usfrom 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 accordancewith 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, ourfacilities and systems; and•litigation, environmental matters, the potential impact of legislation and government regulations, and the use of managementestimates regarding such matters.We caution you that forward-looking statements are not guarantees of future performance and actual results or performancemay be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in thisreport speak as of the filing date of this report. Although we may from time to time voluntarily update our prior forward-lookingstatements, we disclaim any commitment to do so except as required by securities laws.Available InformationOur internet website address is www.sm-energy.com. We routinely post important information for investors on our website.Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports onForm 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securitieslaws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish suchmaterials to the SEC. We also make available through our website our Corporate Governance Guidelines, Code of Business Conductand Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit, Compensation, Executive, and Nominating andCorporate Governance Committees of our Board of Directors. Information on our website is not incorporated by reference into thisreport and should not be considered part of this document.24Glossary of Oil and Gas TermsThe oil and gas terms defined in this section are used throughout this report. The definitions of the terms developed reserves,exploratory well, field, proved reserves, and undeveloped reserves have been abbreviated from the respective definitions under SECRule 4-10(a) of Regulation S-X, as amended effective for fiscal years ending after December 31, 2009. The entire definitions of thoseterms under Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at www.sec.gov.Ad valorem tax. A tax based on the value of real estate or personal property.Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, or other liquid hydrocarbons.Bcf. Billion cubic feet, used in reference to natural gas.BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil or NGLs.BTU. One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degreeFahrenheit.Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.Developed reserves. Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operatingmethods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installedextraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell.Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon knownto be productive.Dry hole. A well found to be incapable of producing either oil, natural gas, and/or NGLs in commercial quantities.Exploratory well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previouslyfound to be productive of oil or natural gas in another reservoir, or to extend a known reservoir beyond its known horizon.Fee properties. The most extensive interest that can be owned in land, including surface and mineral (including oil and natural gas)rights.Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologicalstructural feature or stratigraphic condition.Finding and development cost. Expressed in dollars per BOE. Finding and development cost metrics provide information as to the costof adding proved reserves from various activities, and are widely utilized within the exploration and production industry, as well as byinvestors and analysts. The information used to calculate these metrics is included in the Supplemental Oil and Gas Information sectionin Part II, Item 8 of this report. It should be noted that finding and development cost metrics have limitations. For example, explorationefforts related to a particular set of proved reserve additions may extend over several years. As a result, the exploration costs incurred inearlier periods are not included in the amount of exploration costs incurred during the period in which that set of proved reserves isadded. In addition, consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included incosts incurred. Since the additional development costs that will need to be25incurred in the future before the proved undeveloped reserves are ultimately produced are not included in the amount of costs incurredduring the period in which those reserves were added, those development costs in future periods will be reflected in the costs associatedwith adding a different set of reserves.Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.Frac spread. Hydraulic fracturing requires custom-designed and purpose-built equipment. A “frac spread” is the equipment necessaryto carry out a fracturing job.Gross acre. An acre in which a working interest is owned.Gross well. A well in which a working interest is owned.Horizontal wells. Wells that are drilled at angles greater than 70 degrees from vertical.Lease operating expenses. The expenses incurred in the lifting of crude oil, natural gas, and/or associated liquids from a producingformation to the surface, constituting part of the current operating expenses of a working interest, and also including labor,superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but notincluding lease acquisition, drilling, or completion costs.MBbl. One thousand barrels of crude oil, NGLs, or other liquid hydrocarbons.MBOE. One thousand barrels of oil equivalent.Mcf. One thousand cubic feet, used in reference to natural gas.MMBbl. One million barrels of oil, NGLs, or other liquid hydrocarbons.MMBOE. One million barrels of oil equivalent.MMBtu. One million British thermal units.MMcf. One million cubic feet, used in reference to natural gas.Net acres or net wells. Sum of our fractional working interests owned in gross acres or gross wells.Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number ofoutstanding shares of common stock.NGLs. The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid undervarious levels of higher pressure and lower temperature.NYMEX WTI. New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for crude oil.NYMEX Henry Hub. New York Mercantile Exchange Henry Hub, a common industry benchmark price for natural gas.OPIS. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.PV-10 (Non-GAAP). The present value of estimated future revenue to be generated from the production of estimated net provedreserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs ineffect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and26administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using anannual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of thestandardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative valueof the Company on a comparative basis to other companies and from period to period. This is a non-GAAP measure.Productive well. A well that is producing crude oil, natural gas, and/or NGLs or that is capable of commercial production of thoseproducts.Proved reserves. Those quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated withreasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire,unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used forthe estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to bedetermined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered bythe report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period,unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.Recompletion. The completion of an existing wellbore in a formation other than that in which the well has previously been completed.Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for thepreceding 12-month period.Reserve replacement. Reserve replacement metrics are used as indicators of a company’s ability to replenish annual productionvolumes and grow its reserves, and provide information related to how successful a company is at growing its proved reserve base.These are believed to be useful non-GAAP measures that are widely utilized within the exploration and production industry, as well asby investors and analysts. They are easily calculable metrics, and the information used to calculate these metrics is included in theSupplemental Oil and Gas Information section of Part II, Item 8 of this report. It should be noted that reserve replacement metrics havelimitations. They are limited because they typically vary widely based on the extent and timing of new discoveries and propertyacquisitions. Their predictive and comparative value is also limited for the same reasons. In addition, because the metrics do not embedthe cost or timing of future production of new reserves, they cannot be used as a measure of value creation.Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil, natural gas,and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from otherreservoirs.Resource play. A term used to describe an accumulation of crude oil, natural gas, and/or associated liquid resources known to existover a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.Royalty. The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil,natural gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affectedwell.27Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of crude oil, natural gas, and NGLproduction free of costs of exploration, development, and production operations.Seismic. The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape,and depth of subsurface rock formations.Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurringsedimentary rock.Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based onprices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10 percent annual discount rate. The information forthis calculation is included in Supplemental Oil and Gas Information located in Part II, Item 8 of this report.Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production ofcommercial quantities of oil, natural gas, and associated liquids regardless of whether such acreage contains estimated net provedreserves.Undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where arelatively major expenditure is required for recompletion. The applicable SEC definition of undeveloped reserves provides thatundrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that theyare scheduled to be drilled within five years, unless the specific circumstances justify a longer time.Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the propertyand to share in the production, sales, and costs.28ITEM 1A. RISK FACTORSIn addition to the other information included in this report, the following risk factors should be carefully considered whenevaluating an investment in us.Risks Related to Our BusinessCrude oil, natural gas, and NGL prices are volatile, and declines in prices adversely affect our profitability, financial condition, cashflows, access to capital, and ability to grow.Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and natural gas propertiesdepend heavily on the prices we receive for crude oil, natural gas, and NGL sales. Crude oil, natural gas, and NGL prices also affect ourcash flows available for capital expenditures and other items, our borrowing capacity, and the volume and amount of our crude oil,natural gas, and NGL reserves. For example, the amount of our borrowing base under our credit facility is subject to periodicredeterminations based on crude oil, natural gas, and NGL prices specified by our bank group at the time of redetermination. Inaddition, we may have crude oil and natural gas property impairments or downward revisions of estimates of proved reserves if pricesfall significantly. The decline in commodity prices during 2015 resulted in reductions to our proved reserve volumes and PV-10;reductions in revenues received from the sale of oil, gas, and NGLs, and thus cash flow from operating activities; and recordedimpairments of proved, unproved, and other property. Please refer herein to the captions Significant Developments in 2015 within PartI, Items 1 and 2 Business and Properties; the section Comparison of Financial Results and Trends between 2015 and 2014 and between2014 and 2013 within Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies and Note 11 – Fair ValueMeasurements in Part II, Item 8 for specific discussion.Historically, the markets for crude oil, natural gas, and NGLs have been volatile, and they are likely to continue to be volatile.Wide fluctuations in crude oil, natural gas, and NGL prices may result from relatively minor changes in the supply of and demand forcrude oil, natural gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:•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 areasthat 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 toand maintain crude oil price and production controls;29•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.These factors and the volatility of crude oil, natural gas, and NGL markets make it extremely difficult to predict future crude oil,natural gas, and NGL price movements with any certainty. Declines in crude oil, natural gas, and NGL prices would reduce ourrevenues and could also reduce the amount of crude oil, natural gas, and NGLs that we can produce economically, which could have amaterially adverse effect on us.Weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that wecannot predict.In recent years, the United States and global economies and financial systems have experienced turmoil and upheavalcharacterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability,inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, increased levels of unemployment,and an unprecedented level of intervention by the United States federal government and other governments. Although the United Stateseconomy appears to have stabilized, the extent and timing of a recovery, and whether it can be sustained, are uncertain. Renewedweakness in the United States or other large economies could materially adversely affect our business and financial condition. Forexample:•crude oil, NGL and natural gas prices have recently been lower than at various times in the last decade because of increasedsupply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, whichcould 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 tradereceivables;•the liquidity available under our credit facility 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 ourbusiness, including for the exploration and/or development of reserves;•our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform theirobligations or seek bankruptcy protection; and•variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higherinterest costs for unhedged variable interest rate based borrowings under our credit facility.If we are unable to replace reserves, we will not be able to sustain production.Our future operations depend on our ability to find, develop, or acquire crude oil, natural gas, and NGL reserves that areeconomically producible. Our properties produce crude oil, natural gas, and NGLs at a declining rate over time. In order to maintaincurrent production rates, we must locate and develop or acquire new crude oil, natural gas, and NGL reserves to replace those beingdepleted by production. Without successful drilling or acquisition activities, our reserves and production will decline over time. Inaddition, competition for crude oil and natural gas properties is intense, and many of our competitors have financial, technical, human,and other resources necessary to evaluate and integrate acquisitions that are substantially greater than those available to us.30In the event we do complete an acquisition, its successful impact on our business will depend on a number of factors, many ofwhich are beyond our control. These factors include the purchase price for the acquisition, future crude oil, natural gas, and NGLprices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future netrevenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation, and developmentactivities on the acquired properties, and future abandonment and possible future environmental or other liabilities. There are numerousuncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs andpotential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in theestimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of theacquired properties if they have substantially different operating and geological characteristics or are in different geographic locationsthan our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability toefficiently realize the expected economic benefits of such transactions may be limited.Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility thatmanagement may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseendifficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similarrisks could lead to potential adverse short-term or long-term effects on our operating results and may cause us to not be able to realizeany or all of the anticipated benefits of the acquisitions.Substantial capital is required to develop and replace our reserves.We must make substantial capital expenditures to find, acquire, develop, and produce crude oil, natural gas, and NGL reserves.Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existingwells, prices received for crude oil, natural gas, and NGL sales, our success in locating and developing and acquiring new reserves, andthe orderly functioning of credit and capital markets. If crude oil, natural gas, and NGL prices further decrease or if we encounteroperating difficulties that result in our cash flows from operations being less than expected, we may further reduce our planned capitalexpenditures unless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financingmay not always be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestituresmay not always be of acceptable value to us. Our credit ratings were recently downgraded by two major rating agencies. Thesedowngrades and any further downgrades may make it more difficult or expensive for us to borrow additional funds.During 2015, our revenues decreased significantly from 2014 due to continued declines in commodity prices; however, wewere able to fund our capital program through cash flows from operations, proceeds from divestitures, and financing activities. If ourrevenues continue to decrease in the future due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons,and if we cannot obtain funding through our credit facility, other acceptable debt or equity financing arrangements, or through the saleof assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could begreatly limited.The recent or future downgrades in our credit ratings by various credit rating agencies could impact our access to capital andmaterially adversely affect our business and financial condition.In February 2016, Moody’s Investors Service and Standard & Poor’s downgraded our credit ratings (“Debt Rating”).31Our Debt Rating levels could have materially adverse consequences on our business and future prospects and could:•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, ourability 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•suppliers and financial institutions may lower or eliminate the level of credit provided through payment terms or intradayfunding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our abilityto repay indebtedness.We cannot provide assurance that any of our current Debt Ratings will remain in effect for any given period of time or that aDebt Rating will not be further lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than wedo.We face intense competition from major oil and gas companies, independent oil and gas exploration and production companies,and institutional and individual investors who seek oil and gas investments throughout the world, as well as the equipment, expertise,labor, and materials required to operate crude oil and natural gas properties. Many of our competitors have financial, technical, andother resources exceeding those available to us, and many crude oil and natural gas properties are sold in a competitive bidding processin which our competitors may be able and willing to pay more for exploratory and development prospects and productive properties, orin which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid forproperties. We may not be successful in acquiring and developing profitable properties in the face of this competition. In addition, othercompanies may have a greater ability to continue drilling activities during periods of low natural gas or oil prices and to absorb theburden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials as a resultof intense competition may result in increased costs or the inability to obtain those resources as needed. Also, we compete for humanresources. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on ourbusiness activities, financial condition and results of operations.The loss of key personnel could adversely affect our business.We depend to a large extent on the efforts and continued employment of our executive management team and other keypersonnel. The loss of their services could adversely affect our business. Our drilling success and the success of other activities integralto our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and otherprofessionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attractadditional experienced technical personnel and professionals, our ability to compete could be harmed.32The actual quantities and present value of our proved crude oil, natural gas, and NGL reserves may be less than we have estimated.This report and other of our SEC filings contain estimates of our proved crude oil, natural gas, and NGL reserves and theestimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions requiredby the SEC relating to crude oil, natural gas, and NGL prices, drilling and completion costs, gathering and transportation costs,operating expenses, capital expenditures, effects of governmental regulation, taxes, timing of operations, and availability of funds. Theprocess of estimating crude oil, natural gas, and NGL reserves is complex. The process involves significant decisions and assumptionsin the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates aredependent on many variables, and changes often occur as our knowledge of these variables evolve. Therefore, these estimates areinherently imprecise. In addition, the reserve estimates we make for properties that do not have a significant production history may beless reliable than estimates for properties with lengthy production histories. A lack of production history may contribute to inaccuracy inour estimates of proved reserves, future production rates, and the timing and/or amount of development expenditures.Actual future production; prices for crude oil, natural gas, and NGLs; revenues; production taxes; development expenditures;operating expenses; and quantities of producible crude oil, natural gas, and NGL reserves will most likely vary from those estimated.Any significant variance of any nature could materially affect the estimated quantities of and present value related to proved reservesdisclosed by us, and the actual quantities and present value may be significantly less than we have previously estimated. In addition, wemay adjust estimates of proved reserves to reflect production history, results of exploration, operations and development activity,prevailing crude oil, natural gas, and NGL prices, costs to develop and operate properties, and other factors, many of which are beyondour control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may notcontrol.As of December 31, 2015, 48 percent, or 226.8 MMBOE, of our estimated proved reserves were proved undeveloped, and onepercent, or 5.1 MMBOE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as ofDecember 31, 2015, we estimate approximately $1.9 billion of capital expenditures would be required. Production revenues fromproved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. Inorder to develop our proved developed non-producing reserves, as of December 31, 2015, we estimate capital expenditures ofapproximately $10 million would be required. Although we have estimated our proved reserves and the costs associated with theseproved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled,and actual results may not occur as estimated.You should not assume that the PV-10 and standardized measure of discounted future net cash flows included in this reportrepresent the current market value of our estimated proved crude oil, natural gas, and NGL reserves. Management has based theestimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actualfuture prices and costs may be materially higher or lower. For example, the present value of our proved reserves as of December 31,2015, was estimated using a calculated 12-month average sales price of $2.59 per MMBtu of natural gas (NYMEX Henry Hub spotprice), $50.28 per Bbl of oil (NYMEX WTI spot price), and $20.20 per Bbl of NGL (OPIS spot price). We then adjust these prices toreflect appropriate basis, quality, and location differentials over the period in estimating our proved reserves. During 2015, our monthlyaverage realized natural gas prices, excluding the effect of derivative settlements, were as high as $3.57 per Mcf and as low as $1.91per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative settlements were as high as$54.30 per Bbl and as low as $29.78 per Bbl, and were as high as $18.43 per Bbl and as low as $13.31 per Bbl for NGLs. Many otherfactors will affect actual future net cash flows, including:•amount and timing of actual production;•supply and demand for crude oil, natural gas, and NGLs;33•curtailments or increases in consumption by oil purchasers and natural gas pipelines; and•changes in government regulations or taxes, including severance and excise taxes.The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cashflows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated futurenet cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to be used to calculatePV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, andother risks to which our business and the oil and natural gas industry in general are subject.Our property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expectedbenefits, as well as potential liabilities.Successful property acquisitions require an assessment of a number of factors, some of which are beyond our control. Thesefactors include exploration potential, future crude oil, natural gas, and NGL prices, operating costs, and potential environmental andother liabilities. These assessments are not precise and their accuracy is inherently uncertain.In connection with our acquisitions, we typically perform a customary review of the acquired properties that will not necessarilyreveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of theproperties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, orenvironmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities,including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches ofrepresentations and warranties.In addition, significant acquisitions can change the nature of our operations and business if the acquired properties havesubstantially different operating and geological characteristics or are in different geographic locations than our existing properties. Tothe extent acquired properties are substantially different than our existing properties, our ability to efficiently realize the expectedeconomic benefits of such acquisitions may be limited.Integrating acquired properties and businesses involves a number of other special risks, including the risk that management maybe distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additionalemployees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions.Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities forcertain matters.We regularly sell non-core assets in order to increase capital resources available for core assets and to create organizational andoperational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasingefficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals ofgovernmental agencies or third parties and the availability of purchasers willing to acquire the assets or terms we deem acceptable. Weat times may be required to retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. Themagnitude of any such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transactionand ultimately could be material.34We have limited control over the activities on properties we do not operate.Some of our properties, including a portion of our interests in the Eagle Ford shale in south Texas, are operated by othercompanies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation orfuture development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill andexpertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, theselection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to suchproperties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of theexpenditures of such properties. These limitations and our dependence on the operator and other working interest owners in theseprojects could cause us to incur unexpected future costs and materially and adversely affect our financial condition and results ofoperations.We rely on third-party service providers to conduct drilling and completion and other related operations on properties we operate.Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completionand other related operations. The ability of third-party service providers to perform such operations will depend on those serviceproviders’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital,which in turn will depend upon the supply and demand for oil, natural gas, and NGLs, prevailing economic conditions and financial,business, and other factors. In addition, continued low commodity prices may cause third-party service providers to consolidate ordeclare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider toadequately perform operations could delay drilling or completion or reduce production from the property and adversely affect ourfinancial condition and results of operations.Title to the properties in which we have an interest may be impaired by title defects.We generally rely on title reports in acquiring oil and gas leasehold interests and obtain title opinions only on significantproperties that we drill. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally,undeveloped acreage has greater risk of title defects than developed acreage. Title insurance is not generally available for oil and gasproperties. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work ofexamining records in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease aspecific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in themarketability of the title to us. Generally, under the terms of the operating agreements affecting our properties, any monetary lossattributable to a loss of title is to be borne by all parties to any such agreement in proportion to their interests in such property. Amaterial title defect can reduce the value of a property or render it worthless, thus adversely affecting our financial condition, results ofoperations, and operating cash flow if such property is of sufficient value.Exploration and development drilling may not result in commercially producible reserves.Crude oil and natural gas drilling, completion and production activities are subject to numerous risks, including the risk that nocommercially producible crude oil, natural gas, or associated liquids will be found. The cost of drilling and completing wells is oftenuncertain, and crude oil, natural gas, or associated liquids drilling and production activities may be shortened, delayed, or canceled as aresult of a variety of factors, many of which are beyond our control. These factors include:•unexpected adverse drilling or completion conditions;•title problems;35•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 andequipment, pipe, chemicals, water, sand, and other supplies.The prevailing prices for crude oil, natural gas, and NGLs affect the cost of and the demand for drilling rigs, completion andproduction equipment, and other related services. However, changes in costs may not occur simultaneously with correspondingchanges in commodity prices. The availability of drilling rigs can vary significantly from region to region at any particular time.Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply ofrigs in any region may result in drilling delays and higher drilling costs for the available rigs in that region.Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and othergovernmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability torealize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well,or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore ordevelop our properties.The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. Theseismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if crude oil, natural gas, orNGLs are present, or whether they can be produced economically. The cost of drilling, completing, and operating a well is oftenuncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry holes or wells that areproductive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even ifsufficient amounts of crude oil, natural gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation orexperience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well,significant expenditure to repair the well, and/or the loss and abandonment of the well.Results in our newer resource plays may be more uncertain than results in resource plays that are more developed and havelonger established production histories. We and the industry generally have less information with respect to the ultimate recoverabilityof reserves and the production decline rates in newer resource plays than other areas with longer histories of development andproduction. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the earlydevelopment of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.In addition, a significant part of our strategy involves increasing our inventory of drilling locations. Such multi-year drillinginventories can be more susceptible to long-term uncertainties that could materially alter the occurrence or timing of actual drilling.Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled, although wehave the present intent to do so for locations booked as proved undeveloped locations, or if we will be able to produce crude oil,natural gas, or NGLs from these potential drilling locations.36Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate within aparticular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that weidentify. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations areidentified, the leases for such acreage will expire and we will lose our right to develop the related properties. Our total net acreageexpiring in the next three years represents approximately 32 percent of our total net undeveloped acreage at December 31, 2015.Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce crude oil,natural gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, whichcould adversely affect our financial condition, results of operations and operating cash flow.Part of our strategy involves drilling in existing or emerging resource plays using some of the latest available horizontal drilling andcompletion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling andcompletion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur materialwrite-downs, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.Many of our operations involve utilizing the latest drilling and completion techniques as developed by us and our serviceproviders in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we facewhile drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drillingzone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inabilityto run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, butare not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment theentire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability tosuccessfully clean out the well bore after completion of the final fracture stimulation.Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilledand production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we areunable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems andtakeaway capacity, and/or prices for crude oil, natural gas, and NGLs decline, then the return on our investment for a particular projectmay not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of ourundeveloped acreage could decline in the future.37Uncertainties associated with enhanced recovery methods may result in us not realizing an acceptable return on our investments insuch projects.We inject water into formations on some of our properties to increase the production of crude oil, natural gas, and associatedliquids. We may in the future expand these efforts to more of our properties or employ other enhanced recovery methods in ouroperations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficultto predict. If our enhanced recovery methods do not allow for the extraction of crude oil, natural gas, and associated liquids in a manneror to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, as proposedlegislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methodscould increase substantially.Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may beadversely affected by actions other operators may take when drilling, completing or operating wells that they own.Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. Theowners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, whichcould adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the wellcauses the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drillingand production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further developour proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could causeproduction from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and couldadversely affect the production and reserves from our wells after they re-commence production. We have no control over the operationsor activities of offsetting operators.Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for crude oil, natural gas,and NGL sales.To mitigate a portion of the exposure to potentially adverse market changes in crude oil, natural gas, and NGL prices and theassociated impact on cash flows, we have entered into various derivative contracts. Our derivative contracts in place include swaparrangements for crude oil, natural gas, and NGLs. As of December 31, 2015, we were in a net accrued asset position of $488.4 millionwith respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financial loss incertain circumstances, including instances in which:•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 thecommodity derivative contract arrangement.The risk of one or more counterparties defaulting on their obligations is heightened by continued declines in crude oil, naturalgas, and NGL prices. These circumstances may adversely affect the ability of our counterparties to meet their obligations to us pursuantto derivative transactions, which could reduce our revenues and cash flows from derivative settlements. As a result, our financialcondition, results of operations, and cash flows could be materially affected in an adverse way if our counterparties default on theircontractual obligations under our commodity derivative contracts.38In addition, commodity derivative contracts may limit the prices we receive for our crude oil, natural gas and NGL sales if crudeoil, natural gas, or NGL prices rise substantially over the price established by the commodity derivative contract.The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.Substantially all of our accounts receivable result from crude oil, natural gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall creditrisk because these entities may be similarly affected by various economic and other conditions, including the continued declines incrude oil, natural gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products andnegatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact ouroperating results, as we have numerous options for purchasers in each of our operating regions for our crude oil, natural gas, and NGLproduction. Please refer to Note 1 - Summary of Significant Accounting Policies, under the heading Concentration of Credit Risk andMajor Customers in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers.Additionally, the inability of our co-owners to pay joint interest billings could negatively impact our cash flow and financial ability todrill and complete current and future wells.We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless ofquantities actually shipped, processed, or gathered. If we are unable to deliver the necessary quantities of natural gas to ourcounterparties, our results of operations, financial position, and liquidity could be adversely affected.As of December 31, 2015, we were contractually committed to deliver 2,277 Bcf of natural gas and 36 MMBbl of crude oil, ofwhich the first 1,059 Bcf of natural gas delivered under a certain agreement does not have a deficiency payment. These contracts expireat various dates through 2028. Subsequent to December 31, 2015, we entered into amendments to oil and gas gathering agreementsrelated to certain of our Eagle Ford shale assets, each of which previously did not have a minimum volume commitment. Under theseamendments, we are now committed to deliver 310 Bcf of natural gas and 41 MMBbl of oil through 2034. Subsequent to December 31,2015, we also entered into an amendment to a gas gathering agreement related to certain other Eagle Ford shale assets, which reducedour volume commitment amount as of December 31, 2015, by 829 Bcf. We may enter into additional firm transportation agreements asthe development of our resource plays expands. At the current time, we do not have enough proved developed reserves to offset thesecontractual liabilities, but we expect to develop reserves that will meet or exceed the commitments and therefore do not expect anymaterial shortfalls. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptionsof operations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, or if we furtherlimit our capital expenditures due to further commodity price declines, the requirements to pay for quantities not delivered could have amaterial impact on our results of operations, financial position, and liquidity.Future crude oil, natural gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our assetcarrying values.We follow the successful efforts method of accounting for our crude oil and natural gas properties. All property acquisitioncosts and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether provedreserves have been discovered. If commercial quantities of hydrocarbons are not discovered with an exploratory well, the costs ofdrilling the well are expensed.The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted futurenet cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write downthe costs of each depletion pool to the estimated discounted future net cash flows of that depletion pool. Unproved properties areevaluated at the lower of cost or fair market value. We incurred impairment of proved properties expense and impairment of unprovedproperties expense totaling $468.739million and $78.6 million, respectively, during 2015, $84.5 million and $75.6 million, respectively, during 2014, and $172.6 millionand $46.1 million, respectively, during 2013. We also incurred impairment of other property, plant, and equipment expense totaling$49.4 million during 2015. Commodity prices significantly declined in 2014 and 2015. Continued declines in the prices of crude oil,natural gas, or NGLs or unsuccessful exploration efforts could cause additional proved and/or unproved property impairments in thefuture.We review the carrying value of our properties for indicators of impairment on a quarterly basis using the prices in effect as ofthe end of each quarter. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if crudeoil, natural gas, or NGL prices increase.Lower crude oil, natural gas, or NGL prices could limit our ability to borrow under our credit facility.Our credit facility has a current commitment amount of $1.5 billion, subject to a borrowing base that the lenders redeterminesemi-annually based on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by crude oil, naturalgas, and NGL prices. The current borrowing base under our credit facility is $2.0 billion. The prices of crude oil, natural gas, and NGLsdeclined significantly throughout 2015. These declines in prices, or further declines in prices, could limit our borrowing base andreduce the amount we can borrow under our credit facility. Our amendment to our credit facility in 2015 reduced our borrowing basefrom $2.4 billion to $2.0 billion. This expected reduction was primarily a result of the sale of our Mid-Continent assets in the secondquarter of 2015, as well as adjustments consistent with lower commodity prices. Additionally, divestitures of properties or incurrence ofadditional debt could result in a reduction of our borrowing base.The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economicconditions, and make it more difficult for us to make payments on our debt.As of December 31, 2015, we had $350.0 million of long-term senior unsecured debt outstanding relating to our 6.50% SeniorNotes due 2021 (the “2021 Notes”) that we issued on November 8, 2011; $600.0 million of long-term senior unsecured debtoutstanding relating to our 6.125% Senior Notes due 2022 (the “2022 Notes”) that we issued on November 17, 2014; $400.0 million oflong-term senior unsecured debt outstanding relating to our 6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June29, 2012; $500.0 million of long-term senior unsecured debt outstanding relating to our 5.0% Senior Notes due 2024 (the “2024Notes”) that we issued on May 20, 2013; and $500.0 million of long-term senior unsecured debt outstanding relating to our 5.625%Senior Notes due 2025 (the “2025 Notes”) that we issued on May 21, 2015 (collectively, the 2021 Notes, the 2022 Notes, the 2023Notes, the 2024 Notes, and the 2025 Notes are referred to as our “Senior Notes”); and $202.0 million of outstanding borrowings underour secured credit facility. We had two outstanding letters of credit in the aggregate amount of $200,000 (which reduce the amountavailable for borrowing under the facility on a dollar-for-dollar basis), resulting in $1.3 billion of available borrowing capacity underour credit facility, assuming the borrowing conditions under this facility will be met. Our long-term debt represented 58 percent of ourtotal book capitalization as of December 31, 2015.Our indebtedness could have important consequences for our operations, including:•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 serviceof 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 incurringadditional debt, making acquisitions, and paying dividends;•placing us at a competitive disadvantage compared to our competitors with less debt; and40•making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.Our ability to make payments on our debt, refinance our debt, and fund planned capital expenditures will depend on our abilityto generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, andother factors that are beyond our control. If our business does not generate sufficient cash flow from operations or future sufficientborrowings are not available to us under our credit facility or from other sources, we might not be able to service our debt or fund ourother liquidity needs. If we are unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancelacquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not beable to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition,the terms of our existing or future debt agreements, including our existing and future credit agreements, may prohibit us from pursuingany of these alternatives. Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, andavailability of future financing.Our debt agreements, including the agreement governing our credit facility and the indentures governing the Senior Notes,permit us to incur additional debt in the future, subject to compliance with restrictive covenants under those agreements. In addition,entities we may acquire in the future could have significant amounts of debt outstanding that we could be required to assume, and insome cases accelerate repayment thereof, in connection with the acquisition, or we may incur our own significant indebtedness toconsummate an acquisition.As discussed above, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay aportion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficientfunds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of ourborrowing base or arrange new financing, we may be forced to sell significant assets.The agreements governing our debt contain various covenants that limit our discretion in the operation of our business, could prohibitus from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.Our debt agreements contain restrictive covenants that limit our ability to engage in activities that may be in our long-term bestinterests. Our ability to borrow under our credit facility is subject to compliance with certain financial covenants, including (i)maintenance of a quarterly ratio of total debt to 12-month trailing consolidated adjusted earnings before interest, taxes, depreciation,amortization, and exploration expense of less than 4.0, and (ii) maintenance of an adjusted current ratio of no less than 1.0, each asdefined in our credit facility. Our credit facility also requires us to comply with certain financial covenants, including requirements thatwe maintain certain levels of stockholders’ equity and limit our annual cash dividends to no more than $50.0 million. These restrictionson our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantageof financings, mergers and acquisitions, and other corporate opportunities.The respective indentures governing the Senior Notes also contain covenants that, among other things, limit our ability and theability of our subsidiaries to:•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;41•create liens that secure debt;•enter into transactions with affiliates; and•merge or consolidate with another company.Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in theacceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in theevent of an acceleration of all or a significant portion of our outstanding indebtedness.We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not befully insured.Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death,property damage, well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas and associated liquids, or wellfluids, releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials,spills or releases of brine or other produced or flowback water, subsurface conditions that prevent us from stimulating the plannednumber of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from thewellbore to allow production to begin, fires, adverse weather such as hurricanes or tornadoes, freezing conditions, floods, droughts,formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas such as hydrogen sulfide, and otherenvironmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.Furthermore, if we experience any of the problems with well stimulation and completion activities referenced above, our abilityto explore for and produce crude oil, natural gas, or NGLs may be adversely affected. We could incur substantial losses or otherwisefail to realize reserves in particular formations as a result of the need to shutdown, abandon, or relocate drilling operations, the need tomodify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground watercontamination that might have occurred, and the need to suspend our operations.There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and pastgeneration, handling and disposal of materials, including solid and hazardous wastes and petroleum hydrocarbons. We may incur jointand several, strict liability under applicable United States federal and state environmental laws in connection with releases of petroleumhydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used fornatural gas and oil exploration and production activities for a number of years, often by third parties not under our control. For ouroutside operated properties, we are dependent on the operator for operational and regulatory compliance, and could be subject toliabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringentand costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault orthe legality of the original conduct, including the CERCLA or the Superfund law, the RCRA, the Clean Water Act, the CAA, the OPA,and analogous state laws. Under any implementing regulations, we could be required to remove or remediate previously disposedwastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwatercontamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations toprevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims forpersonal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbonsor other hazardous substances into the environment. As a result, we may incur substantial liabilities to third parties or governmentalentities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.42We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage forsudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused byenvironmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and thenature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe thatthe cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability ormay lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is notfully covered by insurance, we could suffer a material loss.Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs andother risks.Federal, state, tribal, and local authorities extensively regulate the oil and natural gas industry. Legislation and regulationsaffecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may become morestringent and, as a result, may affect, among other things, the pricing or marketing of crude oil, natural gas, and NGL production.Noncompliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agenciesmay lead to substantial administrative, civil, and criminal penalties, including the assessment of natural resource damages, theimposition of significant investigatory and remedial obligations and may also result in the suspension or termination of our operations.The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells andrelated facilities and, in turn, decreases profitability.Governmental authorities regulate various aspects of drilling for and the production of crude oil, natural gas, and NGLs,including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in crude oiland natural gas properties, rights-of-way and easements, environmental matters, occupational health and safety, the sharing of markets,production limitations, plugging, abandonment, and restoration standards, oil and gas operations, and restoration. Public interest inenvironmental protection has increased in recent years, and environmental organizations have opposed, with some success, certainprojects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions ofapproval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or developcertain properties. Federal authorities also may require any of our ongoing or planned operations on federal leases to be delayed,suspended, or terminated. Any such delay, suspension, or termination could have a materially adverse effect on our operations.Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal,state, tribal and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New lawsor regulations, or changes to current requirements, including the designation of previously unprotected wildlife or plant species asthreatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or haveowned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretationsbetween state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability,including joint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges ofcrude oil, natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required tospend substantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues.Any unpermitted release of petroleum or other pollutants from our operations could result not only in cleanup costs, but also naturalresources, real or personal property and other damages and civil and criminal liabilities. The listing of additional wildlife or plantspecies as federally endangered or threatened could result in limitations on exploration and production activities in certain locations.Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered inthe future, may have a materially adverse effect on us.43Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas wherewe operate.Operations in certain of our regions, such as our Rocky Mountain and Permian regions, are adversely affected by seasonalweather conditions and lease stipulations designed to protect various wildlife or plant species. In certain areas on federal lands, drillingand other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in thoseareas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel,which may lead to periodic shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possiblerestrictions may include seasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certaindistance of active raptor nests during fledging, and in big game winter or parturition ranges during winter or calving seasons. Theseconstraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs andadditional operating restrictions or delays.Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, natural gas, andNGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and natural gasproperties, including our unconventional resource plays in the Eagle Ford shale of south Texas, the Bakken/Three Forks formations inNorth Dakota, and the Wolfcamp and Spraberry shale intervals in the Permian Basin. Hydraulic fracturing involves injecting water,sand and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons intothe wellbore. The process is typically regulated by state oil and natural gas commissions. However, the EPA and other federal agencieshave asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking WaterAct (the “SDWA”). The EPA has published an interpretive memorandum and permitting guidance related to regulation of fracturingfluids using this regulatory authority. The EPA announced plans to update its chloride water quality criteria for the protection of aquaticlife under the federal Water Pollution Control Act (the “Clean Water Act”). Flowback and produced water from the hydraulic fracturingprocess contain total dissolved solids, including chlorides, and regulation of these fluids could be affected by the new criteria. The EPAhas delayed issuing a draft criteria document until 2016. The EPA has also announced that it will develop pre-treatment standards fordisposal of wastewater produced from shale gas operations through publicly owned treatment works. The regulations will be developedunder the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. On April 7, 2015, the EPA published aproposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process in the FederalRegister. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it topublicly-owned treatment facilities. The public comment period for the proposed rule ended on July 17, 2015. If the EPA implementsfurther regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant innature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even beprohibited from drilling and/or completing certain wells.Certain states in which we operate, including Texas and Wyoming, have adopted, and other states are considering adopting,regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements onhydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land userestrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing inparticular. Recently, several municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturingwithin city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing outin several cities, counties, and townships across the United States. In the event state, local, or municipal legal44restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incuradditional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit ofexploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.Several federal governmental agencies are actively involved in studies or reviews that focus on environmental aspects andimpacts of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety ofenvironmental issues associated with hydraulic fracturing. On June 4, 2015, the EPA issued a draft assessment of potential impacts todrinking water resources from hydraulic fracturing. The draft report did not find widespread impacts to drinking water from hydraulicfracturing. The EPA’s inspector general released a report on July 16, 2015 recommending increased EPA oversight of permit issuancesas well as the chemicals used in hydraulic fracturing. The United States Department of Energy is also actively involved in research onhydraulic fracturing practices, including groundwater protection.On March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federaland Indian lands, including private surface lands with underlying federal minerals. The rule was scheduled to become effective on June24, 2015, but was temporarily stayed by a federal court. The rule requires public disclosure of chemicals used in hydraulic fracturing onfederal and Indian lands, confirmation that wells used in hydraulic fracturing operations meet certain construction standards,development of appropriate plans for managing flowback water that returns to the surface, heightened standards for interim storage ofrecovered waste fluids, and submission of detailed information to the BLM regarding the geology, depth and location of pre-existingwells. Although several states, tribes, and industry groups filed several pending lawsuits challenging the rule and the BLM’s authority toregulate hydraulic fracturing, the outcome of this litigation is uncertain. If the rule becomes effective, we expect to incur additionalcosts to comply with such requirements that may be significant in nature, and we could experience delays or even curtailment in thepursuit of hydraulic fracturing activities in certain wells on federal and Indian lands. The rule could also affect drilling units that includeboth private and federal mineral resources.Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to requiredisclosure of the chemicals used in the hydraulic fracturing process. If hydraulic fracturing becomes regulated at the federal level, ourfracturing activities could become subject to additional permit or disclosure requirements, associated permitting delays, operationalrestrictions, litigation risk, and potential cost increases. Additionally, certain members of Congress have called upon the United StatesGovernment Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC toinvestigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility ofpursuing natural gas deposits in shales by means of hydraulic fracturing, and the United States Energy Information Administration toprovide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, aswell as uncertainties associated with those estimates. The United States Geological Survey Offices of Energy Resources Program, WaterResources and Natural Hazards and Environmental Health Offices also have ongoing research projects on hydraulic fracturing. Theseongoing studies, depending on their course and outcomes, could spur initiatives to further regulate hydraulic fracturing under theSDWA or other regulatory processes.Further, on August 16, 2012, the EPA issued final rules subjecting all new and modified oil and gas operations (production,processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (“NSPS”) and allexisting and new operations to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rulesalso include NSPS standards for completions of hydraulically fractured gas wells. These standards require the use of reduced emissioncompletion (“REC”) techniques developed in the EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to thegathering line beginning in January 2015. The standards are applicable to newly drilled and fractured wells as well as existing wells thatare refractured. Further, the regulations under NESHAP include maximum achievable control technology (“MACT”) standards for thoseglycol dehydrators and certain storage vessels at major sources of45hazardous air pollutants not currently subject to MACT standards. These rules will require additional control equipment, changes toprocedure, and extensive monitoring and reporting. The EPA stated in January 2013, however, that it intends to reconsider portions ofthe final rule. On September 23, 2013, the EPA published new standards for storage tanks subject to the NSPS. In December 2014, theEPA finalized additional updates to the 2012 NSPS. The amendments clarified stages for flowback and the point at which greencompletion equipment is required and updated requirements for storage tanks and leak detection requirements for processing plants.The EPA has stated that it continues to review other issues raised in petitions for reconsideration.Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation,to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturingprocess could make it easier for third parties opposing such activities to pursue legal proceedings against producers and serviceproviders based on allegations that specific chemicals used in the fracturing process could adversely affect human health or theenvironment, including groundwater. Over the past year, several court cases have addressed aspects of hydraulic fracturing. In a casethat could delay operations on public lands, a court in California held that the BLM did not adequately consider the impact of hydraulicfracturing and horizontal drilling before issuing leases. Courts in New York and Colorado reduced the level of evidence required beforea court will agree to consider alleged damage claims from hydraulic fracturing by property owners. Litigation resulting in financialcompensation for damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation andbring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permittingrequirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays orrestrictions or increased costs in the exploration for, and production of, oil, natural gas, and associated liquids, including from thedevelopment of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state, orlocal laws, or the implementation of new regulations, regarding hydraulic fracturing could potentially cause a decrease in thecompletion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position,results of operations, and cash flows.Requirements to reduce gas flaring could have an adverse effect on our operations.Wells in the Bakken and Three Forks formations in North Dakota, where we have significant operations, produce natural gas aswell as crude oil. Constraints in the current gas gathering and processing network in certain areas have resulted in some of that naturalgas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission, North Dakota’s chiefenergy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations.The Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced,how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells thatcannot meet the capture goals. The Bureau of Land Management (BLM) has also indicated its intent to pursue a rulemaking related tofurther controls on the venting and flaring of natural gas on BLM land. A proposed rule has been sent to the White House Office ofManagement and Budget. These capture requirements, and any similar future obligations in North Dakota or our other locations, mayincrease our operational costs or restrict our production, which could materially and adversely affect our financial condition, results ofoperations and cash flows.Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired ifwe are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of orrecycle the water we use at a reasonable cost and in accordance with applicable environmental rules.The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercialquantities of crude oil, natural gas, and NGLs requires the use and disposal of significant quantities of water.46Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adverselyimpact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on ourability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water,drilling fluids, and other wastes associated with the exploration, development, or production of crude oil, natural gas, and NGLs.Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of surfacewater or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, ortermination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations andfinancial condition.Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and productionmay be eliminated as a result of future legislation.Recent federal budget proposals, if enacted into law, would eliminate certain key United States federal income tax incentivescurrently available to oil and natural gas exploration and production companies. These potential changes include:•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.It is unclear when or if these or similar changes will be enacted. The passage of legislation enacting these or similar changes infederal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and naturalgas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations andcash flows.Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operationsand the demand for crude oil, natural gas, and NGLs.In December 2009, the EPA made a finding that emissions of carbon dioxide, methane, and other “greenhouse gases” endangerpublic health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climaticchanges. Based on this finding, the EPA has over the past four years adopted and implemented a comprehensive suite of regulations torestrict and otherwise regulate emissions of greenhouse gases under existing provisions of the CAA. In particular, the EPA has adoptedtwo sets of rules regulating greenhouse gas emissions under the CAA. One rule requires a reduction in greenhouse gas emissions frommotor vehicles, and the other regulates permitting and greenhouse gas emissions from certain large stationary sources. These EPAregulatory actions have been challenged by various industry groups, initially in the D.C. Circuit, which in 2012 ruled in favor of theEPA in all respects. However, in June 2014, the United States Supreme Court reversed the D.C. Circuit and struck down the EPA’sgreenhouse gas permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhousegases. However, large sources of air pollutants other than greenhouse gases would still be required to implement the best availablecapture technology for greenhouse gases. The EPA has also adopted reporting rules for greenhouse gas emissions from specifiedgreenhouse gas emission sources in the United States, including petroleum refineries as well as certain onshore oil and natural gasextraction and production facilities.Several other kinds of cases on greenhouse gases have been heard by the courts in recent years. While courts have generallydeclined to assign direct liability for climate change to large sources of greenhouse gas emissions, some have required increasedscrutiny of such emissions by federal agencies and permitting authorities.47There is a continuing risk of claims being filed against companies that have significant greenhouse gas emissions, and new claims fordamages and increased government scrutiny will likely continue. Such cases often seek to challenge air emissions permits thatgreenhouse gas emitters apply for, seek to force emitters to reduce their emissions, or seek damages for alleged climate change impactsto the environment, people, and property. Any court rulings, laws or regulations that restrict or require reduced emissions of greenhousegases could lead to increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gasthat we produce.The United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, andalmost one-half of the states have already taken measures to reduce emissions of greenhouse gases, primarily through the planneddevelopment of greenhouse gas emission inventories and/or regional greenhouse gas “cap and trade” programs. Most of these cap andtrade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such asrefineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase isreduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Recently, the Congressional BudgetOffice provided Congress with a study on the potential effects on the United States economy of a tax on greenhouse gas emissions.While “carbon tax” legislation has been introduced in the Senate, the prospects for passage of such legislation are highly uncertain atthis time.On June 25, 2013, President Obama outlined plans to address climate change through a variety of executive actions, includingreduction of methane emissions from oil and gas production and processing operations as well as pipelines and coal mines (the“Climate Plan”). The President’s Climate Plan, along with recent regulatory initiatives and ongoing litigation filed by states andenvironmental groups, signal a new focus on methane emissions, which could pose substantial regulatory risk to our operations. InMarch 2014, President Obama released a strategy to reduce methane emissions, which directed the EPA to consider additionalregulations to reduce methane emissions from the oil and gas sector. On January 14, 2015, the Obama Administration announcedadditional steps to reduce methane emissions from the oil and gas sector by 40 to 45 percent by 2025. These actions include acommitment from the EPA to issue new source performance standards for methane emissions from the oil and gas sector. Pursuant tothis commitment, in September 2015, the EPA proposed emission standards for methane and VOC for sources in the oil and gas sectorconstructed or modified after September 1, 2015. The proposed rules expand the 2012 NSPS for VOC emissions from the oil and gassector to include methane emissions. For sources not affected by the 2012 NSPS, the proposed rule imposes both VOC and methanestandards. In particular, the proposal would require methane reductions from centrifugal and reciprocating compressors, pneumaticpumps, fugitive emissions from well sites and compressor stations and equipment leaks at natural gas processing plants. The proposaldoes not extend to existing sources and EPA has not indicated when it will propose existing source standards. Additionally, in January2016, the BLM proposed additional rules designed to reduce methane venting and flaring from production wells, pneumatic controllersand storage tanks on federal and tribal lands, which are expected to be finalized in 2016. The focus on legislating methane also couldeventually result in:•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 andindustry sectors.In relation to the Climate Plan, both assumed Global Warming Potential (“GWP”) and assumed social costs associated withmethane and other greenhouse gas emissions have been finalized, including a 20% increase in the GWP of methane. Changes to thesemeasurement tools could adversely impact permitting requirements,48application of agencies’ existing regulations for source categories with high methane emissions, and determinations of whether a sourcequalifies for regulation under the CAA.Finally, it should be noted that some scientists have predicted that increasing concentrations of greenhouse gases in the earth’satmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms,droughts, and floods and other climatic events. Some scientists refute these predictions. However, President Obama’s Climate Planemphasizes preparation for such events. If such effects were to occur, our operations could be adversely affected. Potential adverseeffects could include disruption of our production activities, including, for example, damages to our facilities from flooding or increasesin our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coveragein the aftermath of such events. Significant physical effects of climate change could also have an indirect effect on our financing andoperations by disrupting the transportation or process-related services provided by midstream companies, service companies orsuppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages,losses or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climatechange preparation requirements could also impact our costs and planning requirements.Our ability to sell crude oil, natural gas and NGLs, and/or receive market prices for our production, may be adversely affected byconstraints on gathering systems, processing facilities, pipelines and other transportation systems owned or operated by others or byother interruptions.The marketability of our crude oil, natural gas, and NGL production depends in part on the availability, proximity, and capacityof gathering systems, processing facilities, pipelines, and other transportation systems owned or operated by third parties. Anysignificant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although wehave some contractual control over the processing and transportation of our operated production, material changes in these businessrelationships could materially affect our operations. Federal and state regulation of crude oil, natural gas, and NGL production andtransportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines,infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, process,and transport crude oil, natural gas, and NGLs.In particular, if drilling in the Eagle Ford shale and Bakken/Three Forks resource plays continue to be successful, the amount ofcrude oil, natural gas, and NGLs being produced by us and others could exceed the capacity of, and result in strains on, the variousgathering and transportation systems, pipelines, processing facilities, and other infrastructure available in these areas. It will benecessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built ordeveloped to accommodate anticipated production from these areas. Because of the current commodity price environment, certainprocessing, pipeline, and other gathering or transportation projects that might be, or are being, considered for these areas may not bedeveloped timely or at all due to lack of financing or other constraints. Capital and other constraints could also limit our ability to buildor access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points ofsale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficientinfrastructure development or capacity expansion and/or sell production at significantly lower prices, which would adversely affect ourresults of operations and cash flows. In addition, the operations of the third parties on whom we rely for gathering and transportationservices are subject to complex and stringent laws and regulations, which require obtaining and maintaining numerous permits,approvals, and certifications from various federal, state, and local government authorities. These third parties may incur substantialcosts in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services arerevised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs wepay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have amaterial adverse effect on our business, financial condition and results of operations.49A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as aresult of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field laborissues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our productionis interrupted at the same time, it could temporarily and adversely affect our cash flows and results of operations.New technologies may cause our current exploration and drilling methods to become obsolete.The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of newproducts and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitivedisadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors mayhave greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the futureallow them to implement new technologies before we can. One or more of the technologies we currently use or implement in the futuremay become obsolete. We cannot be certain we will be able to implement technologies on a timely basis or at a cost that is acceptableto us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financialcondition may be adversely affected.Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and otherdisruptions.As a crude oil, natural gas, and NGLs producer, we face various security threats, including cybersecurity threats to gainunauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to thesecurity of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threatsfrom terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to suchthreats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel orcapabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results ofoperations, or cash flows.Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gainunauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorizedrelease of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and leadto financial losses from remedial actions, loss of business or potential liability.The threat of terrorism and the impact of military and other action have caused instability in world financial markets and couldlead to increased volatility in prices for crude oil, natural gas, and NGLs, all of which could adversely affect the markets for ouroperations. Energy assets might be specific targets of terrorist attacks. These developments have subjected our operations to increasedrisk and, depending on their occurrence and ultimate magnitude, could have a material adverse effect on our business.50Risks Related to Our Common StockThe price of our common stock may fluctuate significantly, which may result in losses for investors.From January 1, 2015, to February 17, 2016, the low and high intraday trading prices per share of our common stock asreported by the New York Stock Exchange ranged from a low of $8.38 per share in January 2016 to a high of $60.28 per share in May2015. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond ourcontrol. These factors include:•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.We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stockprice could decline as a result.Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders fromreceiving a takeover premium on their investment, which could adversely affect the price of our common stock.Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delayingor preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative votingin the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to makenominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combinationwith each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwisecould involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, theseprovisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limitthe price investors are willing to pay in the future for shares of our common stock.Shares eligible for future sale may cause the market price of our common stock to drop significantly, even if our business is doing well.The potential for sales of substantial amounts of our common stock in the public market may have a materially adverse effect onour stock price. As of February 17, 2016, 68,037,643 shares of our common stock were freely tradable without substantial restriction orthe requirement of future registration under the Securities Act. In addition, restricted stock units (“RSUs”) providing for the issuance ofup to a total of 520,725 shares of our common stock and 716,129 performance share units (“PSUs”) were outstanding. The PSUsrepresent the right to receive, upon settlement of the PSUs after the completion of a three-year performance period, a number of sharesof our common stock that may be from zero to two times the number of PSUs granted, depending on the extent to which the underlyingperformance criteria have been achieved and the extent to which the PSUs have vested. As of February 17, 2016, there were68,077,546 shares of our common stock outstanding.51We may not always pay dividends on our common stock.Payment of future dividends remains at the discretion of our Board of Directors, and will continue to depend on our earnings,capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to a covenant in our creditfacility limiting our annual cash dividends to no more than $50.0 million, and to covenants in the indentures for our Senior Notes thatlimit our ability to pay dividends beyond a certain amount. Our Board of Directors may determine in the future to reduce the currentsemi-annual dividend rate of $0.05 per share, or discontinue the payment of dividends altogether.ITEM 1B. UNRESOLVED STAFF COMMENTSWe have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.ITEM 3. LEGAL PROCEEDINGSFrom time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normalcourse of business. As of the filing date of this report, no legal proceedings are pending against us that we believe individually orcollectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.ITEM 4. MINE SAFETY DISCLOSURESThese disclosures are not applicable to us.52PART IIITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIESMarket Information. Our common stock is currently traded on the New York Stock Exchange under the ticker symbol “SM.”The following table presents the range of high and low intraday sales prices per share for the indicated quarterly periods in 2015 and2014, as reported by the New York Stock Exchange:Quarter Ended High LowDecember 31, 2015 $42.23 $18.06September 30, 2015 $45.98 $18.21June 30, 2015 $60.28 $43.70March 31, 2015 $53.31 $31.01 December 31, 2014 $79.89 $29.41September 30, 2014 $90.38 $74.57June 30, 2014 $85.39 $71.00March 31, 2014 $90.22 $69.03PERFORMANCE GRAPHThe following performance graph compares the cumulative return on our common stock, for the period beginningDecember 31, 2010, and ending on December 31, 2015, with the cumulative total returns of the Dow Jones U.S. Exploration andProduction Index, and the Standard & Poor’s 500 Stock Index.COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNSThe preceding information under the caption Performance Graph shall be deemed to be furnished, but not filed with the SEC.Holders. As of February 17, 2016, the number of record holders of our common stock was 71. Based upon inquiry,management believes that the number of beneficial owners of our common stock is approximately 21,200.53Dividends. We have paid cash dividends to our stockholders every year since 1940. Annual dividends of $0.05 per share werepaid in each of the years 1998 through 2004. Annual dividends of $0.10 per share were paid in each of the years 2005 through 2015.We expect our practice of paying dividends on our common stock to continue, although the payment and amount of future dividendswill continue to depend on our earnings, cash flow, capital requirements, financial condition, and other factors, including the discretionof our Board of Directors. In addition, the payment of dividends is subject to covenants in our credit facility that limit our annualdividend payment to no more than $50.0 million per year. We are also subject to certain covenants under our Senior Notes that restrictcertain payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by this covenant.Based on our current performance, we do not anticipate that these covenants will restrict future annual dividend payments in amountsnot to exceed $0.10 per share of common stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.8million and $6.7 million for the years ended December 31, 2015, and December 31, 2014, respectively.Restricted Shares. We have no restricted shares outstanding as of December 31, 2015, aside from Rule 144 restrictions onshares held by insiders and shares issued to members of the Board of Directors under our Equity Incentive Compensation Plan (“EquityPlan”).Purchases of Equity Securities by the Issuer and Affiliated Purchasers. The following table provides information aboutpurchases by the Company and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicatedquarters and year ended December 31, 2015, of shares of the Company’s common stock, which is the sole class of equity securitiesregistered by the Company pursuant to Section 12 of the Exchange Act.ISSUER PURCHASES OF EQUITY SECURITIES Total Number ofSharesPurchased(1) Weighted AveragePrice Paid perShare Total Number of SharesPurchased as Part ofPublicly AnnouncedProgram Maximum Number ofShares that May Yetbe Purchased Underthe Program(2)January 1, 2015 -March 31, 2015465 $52.34 — 3,072,184April 1, 2015 -June 30, 201598 $56.22 — 3,072,184July 1, 2015 -September 30, 2015186,177 $45.50 — 3,072,184October 1, 2015 -October 31, 20154,988 $35.39 — 3,072,184November 1, 2015 -November 30, 2015— $— — 3,072,184December 1, 2015 -December 31, 2015— $— — 3,072,184Total October 1, 2015 -December 31, 20154,988 $35.39 — 3,072,184Total191,728 $45.27 — 3,072,184 ____________________________________________(1)All shares purchased in 2015 were purchased by us to offset grantee tax withholding obligations that arose upon the delivery of outstanding sharesunderlying RSUs and PSUs delivered under the terms of grants under the 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 authorizationto 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 mayrepurchase 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 transactionsor privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indenturesgoverning our Senior Notes and compliance with securities laws. Stock repurchases may be funded with54existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued atany time. Please refer to Dividends above for a description of our dividend limitations.55ITEM 6. SELECTED FINANCIAL DATAThe following table sets forth selected supplemental financial and operating data as of the dates and periods indicated. Thefinancial data for each of the five years presented were derived from our consolidated financial statements. The following data shouldbe read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7of this report, which includes a discussion of factors materially affecting the comparability of the information presented, and inconjunction with our consolidated financial statements included in this report. Years Ended December 31, 2015 2014 2013 2012 2011 (in millions, except per share data)Total operating revenues and otherincome$1,557.0 $2,522.3 $2,293.4 $1,505.1 $1,603.3Net income (loss)$(447.7) $666.1 $170.9 $(54.2) $215.4Net income (loss) per share: Basic$(6.61) $9.91 $2.57 $(0.83) $3.38Diluted$(6.61) $9.79 $2.51 $(0.83) $3.19Total assets at year-end (1)$5,621.6 $6,483.1 $4,678.1 $4,179.0 $3,784.0Long-term debt: Revolving credit facility$202.0 $166.0 $— $340.0 $—3.50% Senior ConvertibleNotes, net of debt discount (1)$— $— $— $— $284.7Senior Notes, net ofunamortized deferred financingcosts (1)$2,316.0 $2,166.4 $1,572.9 $1,079.5 $685.4Cash dividends declared and paidper common share$0.10 $0.10 $0.10 $0.10 $0.10____________________________________________(1) Prior period amounts have been reclassified to conform to the current period presentation on the accompanying financial statements. Please refer to thecaption Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion of the change inpresentation of debt issuance costs on the accompanying balance sheets.56Supplemental Selected Financial and Operations Data For the Years Ended December 31, 2015 2014 2013 2012 2011Balance Sheet Data (in millions) Total working capital (deficit)$216.5 $(39.6) $8.4 $(201.0) $(42.6)Total stockholders’ equity$1,852.4 $2,286.7 $1,606.8 $1,414.5 $1,462.9Weighted-average common shares outstanding (in thousands) Basic67,723 67,230 66,615 65,138 63,755Diluted67,723 68,044 67,998 65,138 67,564Reserves Oil (MMBbl)145.3 169.7 126.6 92.2 71.7Gas (Bcf)1,264.0 1,466.5 1,189.3 833.4 664.0 NGLs (MMBbl)115.4 133.5 103.9 62.3 27.5MMBOE471.3 547.7 428.7 293.4 209.9Production and Operations (in millions) Oil, gas, and NGL production revenue$1,499.9 $2,481.5 $2,199.6 $1,473.9 $1,332.4Oil, gas, and NGL production expense$723.6 $715.9 $597.0 $391.9 $290.1Depletion, depreciation, amortization, and asset retirementobligation liability accretion$921.0 $767.5 $822.9 $727.9 $511.1General and administrative$157.7 $167.1 $149.6 $119.8 $118.5Production Volumes Oil (MMBbl)19.2 16.7 13.9 10.4 8.1Gas (Bcf)173.6 152.9 149.3 120.0 100.3NGLs (MMBbl)16.1 13.0 9.5 6.1 3.5MMBOE64.2 55.1 48.3 36.5 28.3Realized price Oil (per Bbl)$41.49 $80.97 $91.19 $85.45 $88.23Gas (per Mcf)$2.57 $4.58 $3.93 $2.98 $4.32NGLs (per Bbl)$15.92 $33.34 $35.95 $37.61 $53.32Expense per BOE Lease operating expense$3.73 $4.28 $4.49 $4.54 $4.97Transportation costs$6.02 $6.11 $5.34 $3.81 $3.05Production taxes$1.13 $2.13 $2.19 $2.00 $1.90Ad valorem tax expense$0.39 $0.46 $0.33 $0.39 $0.33Depletion, depreciation, amortization, and asset retirementobligation liability accretion$14.34 $13.92 $17.02 $19.95 $18.07General and administrative$2.46 $3.03 $3.09 $3.28 $4.19Statement of Cash Flow Data (in millions) Provided by operating activities$978.4 $1,456.6 $1,338.5 $922.0 $760.5Used in investing activities$(1,144.6) $(2,478.7) $(1,192.9) $(1,457.3) $(1,264.9)Provided by financing activities$166.2 $740.0 $130.7 $422.1 $618.557ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONSThis discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statementsin Part I, Items 1 and 2 of this report for important information about these types of statements.Overview of the CompanyGeneral OverviewWe are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, andNGLs in onshore North America. We currently have development positions in the Eagle Ford shale, Bakken/Three Forks and PermianBasin resource plays that are the focus of our capital investment program. We also have a smaller delineation and exploration programin the Powder River Basin. We have built a portfolio of onshore properties primarily through early entry into existing and emergingresource plays. This portfolio is comprised of properties with established production and reserves, prospective drilling opportunities,and unconventional resource prospects, which we believe provide for stable and predictable production and reserves growth.Our strategic objective is to profitably build our ownership and operatorship of North American oil, gas, and NGL producingassets that have high operating margins and significant opportunities for additional economic investment. We pursue growthopportunities through both exploration and acquisitions, and we seek to maximize the value of our assets through industry leadingtechnology application and outstanding operational execution. We focus on achieving high full-cycle economic returns on ourinvestments and maintaining a simple, strong balance sheet through a conservative approach to leverage.In 2015, we had the following financial and operational results:•We had record annual production for 2015. Our average daily production for 2015 was 52.7 MBbls of oil, 475.7 MMcf ofgas, and 44.0 MBbls of NGLs, for an average daily equivalent production rate of 175.9 MBOE, compared with 151.1MBOE in 2014, an increase of 16 percent year-over-year. Please refer to the caption Production Results below for additionaldiscussion.•At year-end 2015, we had estimated proved reserves of 471.3 MMBOE, of which 55 percent were liquids (oil and NGLs)and 52 percent were characterized as proved developed. We added 160.6 MMBOE through our drilling program, themajority of which related to our activity in the Eagle Ford shale and the Bakken/Three Forks plays, and acquired 1.2MMBOE. We had a positive performance revision of 47.3 MMBOE due to improved performance in our Eagle Ford shaleand Bakken/Three Forks plays related to enhanced completions and reductions in operating expenses, which extended theeconomic lives of our wells. This upward revision was offset by a 116.5 MMBOE negative price revision due to the declinein commodity prices in 2015 and 79.4 MMBOE of proved undeveloped reserves removed due to the five-year rule. Wedivested of 25.4 MMBOE of proved reserves primarily in our Mid-Continent region. Our proved reserve life decreased to7.3 years in 2015 compared to 9.9 years in 2014. Please refer to Reserves included in Part I, Items 1 and 2 of this report foradditional discussion.•The standardized measure of discounted future net cash flows was $1.9 billion as of December 31, 2015, compared with$5.7 billion as of December 31, 2014. The standardized measure calculation is presented in the Supplemental Oil and GasInformation section located in Part II, Item 8 of this report.•We recorded a net loss of $447.7 million, or $6.61 per diluted share, for the year ended December 31, 2015. This compareswith net income of $666.1 million, or $9.79 per diluted share, for the year ended58December 31, 2014. The net loss in 2015 was driven largely by proved and unproved property impairments of $468.7million and $78.6 million, respectively, as a result of the decline in commodity prices. Please refer to the captionComparison of Financial Results and Trends between 2015 and 2014 and between 2014 and 2013 below for additionaldiscussion regarding the components of net income (loss).•We had net cash flow provided by operating activities of $978.4 million for the year ended December 31, 2015, comparedwith $1.5 billion for the year ended December 31, 2014, which was a decrease of 33 percent year-over-year. Please refer toAnalysis of cash flow changes between 2015 and 2014 and between 2014 and 2013 below for additional discussion.•Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2015, was $1.1 billion, comparedwith $1.6 billion for the same period in 2014. Please refer to Non-GAAP Financial Measures below for additionaldiscussion, including our definition of adjusted EBITDAX and reconciliations of our net income (loss) and net cashprovided by operating activities to adjusted EBITDAX.•Costs incurred for oil and gas property acquisition, exploration and development activities for the year ended December 31,2015, totaled $1.4 billion. The majority of our drilling and completion costs incurred during this period were in our EagleFord shale and Bakken/Three Forks programs. Please refer to the caption Production Results below for the number ofoperated wells completed in these programs during 2015. Additionally, we built an inventory of wells drilled during 2015,which we expect to be completed in future years. Total costs incurred for the same period in 2014 totaled $2.7 billion,which included the acquisition of proved and unproved properties in our Gooseneck prospect area and in the Powder RiverBasin for approximately $561.6 million. Please refer to the caption Costs Incurred in Oil and Gas Producing Activitiesbelow for additional discussion.Oil, Gas, and NGL PricesOur financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, andNGL production, which can fluctuate dramatically. We sell the majority of our gas under contracts using first-of-the-month indexpricing, which means gas produced in a given month is sold at the first-of-the-month price regardless of the spot price on the day thegas is produced. For assets where high BTU gas is sold at the wellhead, we also receive additional value for the higher energy contentcontained in the gas stream. Our NGL production is generally sold using contracts paying us a monthly average of the posted OPISdaily settlement prices, adjusted for processing, transportation, and location differentials. Our oil is sold using contracts paying usvarious industry posted prices, adjusted for basis differentials. We are paid the average of the daily settlement price for the respectiveposted prices for the period in which the product is sold, adjusted for quality, transportation, American Petroleum Institute (“API”)gravity, and location differentials. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the averageprice for the respective period, before the effects of derivative settlements, unless otherwise indicated.59The following table summarizes commodity price data, as well as the effects of derivative settlements as further discussed underthe caption Derivative Activity below, for the years ended December 31, 2015, 2014, and 2013: For the Years Ended December 31, 2015 2014 2013Crude Oil (per Bbl): Average NYMEX price$48.68 $93.03 $97.99Realized price, before the effect of derivative settlements$41.49 $80.97 $91.19Effect of derivative settlements$18.85 $1.71 $(1.27) Natural Gas: Average NYMEX price (per MMBtu)$2.61 $4.35 $3.73Realized price, before the effect of derivative settlements (per Mcf)$2.57 $4.58 $3.93Effect of derivative settlements (per Mcf) (1)$0.71 $(0.18) $0.21 NGLs (per Bbl): (2) Average OPIS price$19.76 $38.93 $40.44Realized price, before the effect of derivative settlements$15.92 $33.34 $35.95Effect of derivative settlements$1.69 $0.84 $0.71____________________________________________(1) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of earlysettlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivativesettlements 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 representour product mix for NGL production. Realized prices reflect our actual product mix.While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, theprices we receive are affected by quality, energy content, location, and transportation differentials for these products. We expect future prices for oil, gas, and NGLs to continue to be volatile. In addition to supply and demand fundamentals, as aglobal commodity, the price of oil will continue to be impacted by real or perceived geopolitical risks in oil producing regions of theworld, particularly the Middle East. The relative strength of the U.S. dollar compared to other currencies also affects the price of oil. Inlate 2015, the U.S. lifted its ban on the export of crude oil, which we expect to provide potential for market expansion. Crude oil pricesdeclined throughout 2015 due to slower global economic growth combined with excess global supply. We expect this imbalancebetween supply and demand to remain for the foreseeable future keeping crude oil prices under downward pressure and at levels belowtheir five-year average. Gas prices also remain under downward pressure as supply exceeds demand, resulting in higher levels of gas instorage compared to the prior year and compared to the five-year average. Excess supply of ethane and propane with higher volumes instorage than historical averages resulted in a further drop in pricing for those products throughout 2015. In response to lower oil, gas,and NGL prices, industry participants significantly cut capital spending in 2015, with additional cuts expected in 2016. We expect thelower capital spending by industry participants to eventually result in a decrease in supply providing upside to commodity pricing forall products.60The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs (sameproduct mix as discussed under the table above) as of February 17, 2016, and December 31, 2015: As of February 17,2016 As of December 31,2015NYMEX WTI oil (per Bbl)$37.77 $41.34NYMEX Henry Hub gas (per MMBtu)$2.30 $2.53OPIS NGLs (per Bbl)$16.12 $17.48Derivative ActivityWe use financial derivative instruments as part of our financial risk management program. We have a financial risk managementpolicy governing our use of derivatives. The amount of our production covered by derivatives is driven by the amount of debt on ourbalance sheet and the level of capital commitments and long-term obligations we have in place. With our current derivative contracts,we believe we have partially reduced our exposure to volatility in commodity prices in the near term. Please refer to Note 10 -Derivative Financial Instruments in Part II, Item 8 of this report and the caption titled Commodity Price Risk in Overview of Liquidityand Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.2015 Operational Activity and Financial ResultsOperational Activities. 2015 was a year of transition as the broader oil and gas industry adjusted to lower commodity prices. Wescaled back our operated activity during the year by reducing the number of active drilling rigs from 17 to six and deferring thecompletion of certain drilled wells. The primary focus of our operated drilling activity in 2015 was the development of our Eagle Fordshale and Bakken/Three Forks assets. We realized significant drilling and completion cost reductions during 2015, as our serviceproviders responded to continued commodity price declines. While production declined from quarter to quarter throughout 2015, wehad record production for the full-year 2015, driven primarily by the activity in our operated Eagle Ford shale and Bakken/Three Forksdevelopment programs.In our operated Eagle Ford shale program, we began the year operating five drilling rigs and released two rigs throughout theyear. Our development program shifted to utilizing longer laterals and completions with higher sand loadings, which resulted inimproved well performance. Throughout the year, we tested spacing and the prospectivity of the Upper Eagle Ford on our acreage. Asof December 31, 2015, in our operated Eagle Ford shale program, we had 76 gross and net wells that were drilled but not completed.In our outside-operated Eagle Ford shale program, the operator began 2015 running seven rigs and dropped six rigs throughoutthe year, exiting the year with one rig in operation.In our Bakken/Three Forks program, we started the year operating five drilling rigs and released three rigs during the year. Wecontinue to focus most of our activity in Divide County, North Dakota, where we are developing the Bakken and Three Forks intervalsand testing completion optimizations and down-spacing. As of December 31, 2015, in our operated Bakken/Three Forks program, wehad 48 gross wells (40 net) that were drilled but not completed.In our Permian program, we started 2015 operating two drilling rigs and released both rigs by mid-year. A large portion of ourleasehold position in this region is held by production.We curtailed activity in our delineation and exploration programs in 2015 to focus on preserving our more prospective acreage.In our Powder River Basin program, we started 2015 operating four drilling rigs and decreased our rig count over 2015, exiting the yearwith one rig in operation.61Mid-Continent Divestitures. During the second quarter of 2015, we completed the divestiture of our Mid-Continent assets inseparate transactions for total cash proceeds received at closing, which reflect the aggregate gross purchase price net of closingadjustments (referred throughout this report as “divestiture proceeds”), of $316.8 million, with a net gain of $108.4 million. Please referto Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additional information, as this net gainwas partially offset by write-downs on certain other assets held for sale and sold during 2015. In conjunction with the divestiture of ourMid-Continent assets, we closed our regional office in Tulsa, Oklahoma.Production Results. The table below provides a regional breakdown of our production for 2015: South Texas &Gulf Coast RockyMountain Permian Mid-Continent Total (1)Production: Oil (MMBbl)7.9 9.5 1.8 — 19.2Gas (Bcf)149.5 9.3 5.1 9.7 173.6NGLs (MMBbl)15.7 0.3 — — 16.1Equivalent (MMBOE) (1)48.5 11.3 2.7 1.7 64.2Avg. Daily Equivalents (MBOE/d)132.9 31.1 7.4 4.6 175.9Relative percentage75% 18% 4% 3% 100%____________________________________________(1) Amounts may not calculate due to rounding.For the year ended December 31, 2015, we completed 66 gross and net wells in our operated Eagle Ford shale program and 41gross wells (37 net) in our operated Bakken/Three Forks program. Please refer to Comparison of Financial Results and Trends between2015 and 2014 and between 2014 and 2013 and A year-to-year overview of selected production and financial information, includingtrends below for additional discussion on production.Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration anddevelopment activities, whether capitalized or expensed, are summarized as follows: For the Year Ended December 31, 2015 (in millions)Development costs$1,234.1Exploration costs132.5Acquisitions Proved properties10.0Unproved properties18.4Total, including asset retirement obligation (1)$1,395.0____________________________________________(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 foradditional discussion on the costs included in this table.Costs incurred in oil and gas producing activities, excluding proved and unproved acquisitions, estimated asset retirementobligations, capitalized interest, and support facility allocations, for the year ended December 31, 2015, totaled approximately $1.3billion and were primarily incurred in the development of our Eagle Ford shale and Bakken/Three Forks programs. 62Impairment of Proved and Unproved Properties and Other Property and Equipment. We recorded impairment of provedproperties expense of $468.7 million, abandonment and impairment of unproved properties expense of $78.6 million, and impairmentof other property and equipment expense of $49.4 million for the year ended December 31, 2015. These impairment expenses wereprimarily due to continued commodity price declines, as well as our decision to reduce capital spending in our east Texas explorationprogram in light of the sustained, low commodity price environment. Please refer to Comparison of Financial Results and Trendsbetween 2015 and 2014 and between 2014 and 2013 below for further discussion.2025 Notes. On May 21, 2015, we issued $500.0 million in aggregate principal amount of our 5.625% Senior Notes, at par, thatmature on June 1, 2025. We received net proceeds of $491.0 million from this issuance, which we used for the tender and redemptionof the $350.0 million principal amount of our 6.625% Senior Notes due 2019 (the “2019 Notes”), as well as to repay outstandingborrowings under our credit facility and for general corporate purposes. Through these transactions, we extended the first maturity onour Senior Notes to 2021 and reduced our weighted average borrowing rate. Please refer to Note 5 - Long-Term Debt in Part II, Item 8of this report for additional information.Revolving Credit Facility. In the third quarter of 2015, our lenders decreased the borrowing base under our credit facility to $2.0billion from $2.4 billion, primarily a result of the sale of our Mid-Continent assets in the second quarter of 2015, as well as adjustmentsconsistent with lower commodity prices. Please refer to Overview of Liquidity and Capital Resources below for additional discussion ofour credit facility.Outlook for 2016Our goal is to maintain a strong balance sheet and preserve liquidity in the current commodity price environment. We expect toincur capital expenditures below adjusted EBITDAX in order to minimize any impact to our total debt. We believe this focus on ourliquidity will best preserve our balance sheet and will give us the flexibility to adapt as industry conditions change. Please refer toOverview of Liquidity and Capital Resources below for additional discussion on how we expect to fund our 2016 capital program.Our capital program for 2016 will be approximately $705 million, of which approximately 85 percent will be invested in drillingand completion activities with the focus on our core development programs in the Bakken/Three Forks, Permian Basin, and Eagle Fordshale. We plan to continue our focus on conducting safe operations even as we pursue cost saving measures throughout our business.In our operated Eagle Ford shale program, we entered 2016 operating three drilling rigs. We dropped two operated drilling rigsat the start of 2016 and expect to drop the remaining drilling rig during the third quarter. We plan to utilize one frac spread through thethird quarter of 2016. We expect to focus the majority of our investment on wells that were drilled but uncompleted at year-end 2015and to meet lease obligations.In our outside-operated Eagle Ford shale program, we expect the operator will further slow its pace of development in 2016.In our operated Bakken/Three Forks program, we entered 2016 operating two drilling rigs. We expect to run a two drilling rigprogram until the second quarter of 2016, at which time we expect to release one drilling rig and run a one rig program for theremainder of the year.In our Permian Basin program, we began operating one drilling rig in early 2016 and currently expect to increase to two drillingrigs during the second quarter of 2016. Our focus will be on developing the Wolfcamp and Spraberry shale intervals on our SweetiePeck property in Upton County, Texas. We dropped our last operated drilling rig in our Powder River Basin program in mid-February 2016.63Financial Results of Operations and Additional Comparative DataThe tables below provide information regarding selected production and financial information for the quarter endedDecember 31, 2015, and the immediately preceding three quarters. A detailed discussion follows. For the Three Months Ended December 31, September 30, June 30, March 31, 2015 2015 2015 2015 (in millions, except for production data)Production (MMBOE)14.9 16.1 16.5 16.8Oil, gas, and NGL production revenue$298.7 $366.6 $441.3 $393.3Oil, gas, and NGL production expense$169.2 $184.6 $173.7 $196.2Depletion, depreciation, amortization, and assetretirement obligation liability accretion$240.0 $243.9 $219.7 $217.4Exploration$37.9 $19.7 $25.5 $37.4General and administrative$33.6 $37.8 $42.6 $43.6Net income (loss)$(340.3) $3.1 $(57.5) $(53.1)____________________________________________Note: Amounts may not calculate due to rounding.Selected Performance Metrics: For the Three Months Ended December 31, September 30, June 30, March 31, 2015 2015 2015 2015Average net daily production equivalent (MBOEper day)162.1 174.5 181.0 186.4Lease operating expense (per BOE)$3.85 $3.86 $3.26 $3.96Transportation costs (per BOE)$6.10 $6.27 $5.64 $6.08Production taxes as a percent of oil, gas, and NGLproduction revenue5.1% 4.2% 5.2% 4.8%Ad valorem tax expense (per BOE)$0.38 $0.40 $0.25 $0.52Depletion, depreciation, amortization, and assetretirement obligation liability accretion (per BOE)$16.10 $15.19 $13.34 $12.96General and administrative (per BOE)$2.26 $2.35 $2.59 $2.60____________________________________________Note: Amounts may not calculate due to rounding.64A year-to-year overview of selected production and financial information, including trends: For the Years Ended December 31, Amount Change Between Percent Change Between 2015 2014 2013 2015/2014 2014/2013 2015/2014 2014/2013Net production volumes (1) Oil (MMBbl)19.2 16.7 13.9 2.6 2.7 15 % 19 %Gas (Bcf)173.6 152.9 149.3 20.7 3.6 14 % 2 %NGLs (MMBbl)16.1 13.0 9.5 3.1 3.5 24 % 37 %Equivalent (MMBOE)64.2 55.1 48.3 9.1 6.8 16 % 14 %Average net daily production (1) Oil (MBbl per day)52.7 45.6 38.2 7.0 7.4 15 % 19 %Gas (MMcf per day)475.7 419.0 409.2 56.7 9.8 14 % 2 %NGLs (MBbl per day)44.0 35.6 26.0 8.4 9.6 24 % 37 %Equivalent (MBOE per day)175.9 151.1 132.4 24.9 18.6 16 % 14 %Oil, gas, and NGL production revenue (in millions) Oil production revenue$797.3 $1,348.3 $1,271.5 $(551.0) $76.8 (41)% 6 %Gas production revenue447.0 699.8 586.3 (252.8) 113.5 (36)% 19 %NGL production revenue255.6 433.4 341.8 (177.8) 91.6 (41)% 27 %Total$1,499.9 $2,481.5 $2,199.6 $(981.6) $281.9 (40)% 13 %Oil, gas, and NGL production expense (in millions) Lease operating expense$239.6 $235.8 $216.9 $3.8 $18.9 2 % 9 %Transportation costs386.6 337.1 258.2 49.5 78.9 15 % 31 %Production taxes72.4 117.2 105.8 (44.8) 11.4 (38)% 11 %Ad valorem tax expense25.0 25.8 16.1 (0.8) 9.7 (3)% 60 %Total$723.6 $715.9 $597.0 $7.7 $118.9 1 % 20 %Realized price Oil (per Bbl)$41.49 $80.97 $91.19 $(39.48) $(10.22) (49)% (11)%Gas (per Mcf)$2.57 $4.58 $3.93 $(2.01) $0.65 (44)% 17 %NGLs (per Bbl)$15.92 $33.34 $35.95 $(17.42) $(2.61) (52)% (7)%Per BOE$23.36 $45.01 $45.50 $(21.65) $(0.49) (48)% (1)%Per BOE data (1) Production costs: Lease operating expense$3.73 $4.28 $4.49 $(0.55) $(0.21) (13)% (5)% Transportation costs$6.02 $6.11 $5.34 $(0.09) $0.77 (1)% 14 % Production taxes$1.13 $2.13 $2.19 $(1.00) $(0.06) (47)% (3)%Ad valorem tax expense$0.39 $0.46 $0.33 $(0.07) $0.13 (15)% 39 %General and administrative$2.46 $3.03 $3.09 $(0.57) $(0.06) (19)% (2)%Depletion, depreciation, amortization, andasset retirement obligation liabilityaccretion$14.34 $13.92 $17.02 $0.42 $(3.10) 3 % (18)%Derivative settlement gain (2)(3)$7.98 $0.22 $0.42 $7.76 $(0.20) 3,527 % (48)%Earnings per share information Basic net income (loss) per common share$(6.61) $9.91 $2.57 $(16.52) $7.34 (167)% 286 %Diluted net income (loss) per commonshare$(6.61) $9.79 $2.51 $(16.40) $7.28 (168)% 290 %Basic weighted-average common sharesoutstanding (in thousands)67,723 67,230 66,615 493 615 1 % 1 %Diluted weighted-average common sharesoutstanding (in thousands)67,723 68,044 67,998 (321) 46 — % — %65____________________________________________(1) Amounts and percentage changes may not calculate due to rounding.(2) We discontinued hedge accounting on January 1, 2011. As a result, fair values at December 31, 2010, were frozen in accumulated other comprehensive loss(“AOCL”) and were reclassified into earnings as the original derivative transactions settled, the last of which settled in the third quarter of 2013. For theyear ended December 31, 2013, derivative settlements are included within the other operating revenues and derivative gain line items in the accompanyingstatements of operations. All derivative settlements for the years ended December 31, 2015, and 2014, are included within the derivative gain line itemonly.(3) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of earlysettlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivativesettlements by $0.09 per Mcf and $0.04 per Mcf for the years ended December 31, 2015, and 2014, respectively.We present per BOE information because we use this information to evaluate our performance relative to our peers and toidentify and measure trends we believe may require additional analysis. Average daily production for the year ended December 31,2015, increased 16 percent compared to the same period in 2014, driven by continued development of our Eagle Ford shale andBakken/Three Forks programs. We expect production to decrease in 2016 when compared to 2015 as a result of the sale of our Mid-Continent assets during the second quarter of 2015 and reduced drilling and completion activity in late 2015 and throughout 2016 inresponse to the sustained low commodity price environment. Please refer to Comparison of Financial Results and Trends between 2015and 2014 and between 2014 and 2013 below for additional discussion.Changes in production volumes, revenues, and costs reflect the highly volatile nature of our industry. Our realized price on aper BOE basis for the year ended December 31, 2015, decreased 48 percent compared to 2014 as a result of significantly lowercommodity prices. Our derivative contracts resulted in a $7.98 settlement gain on a per BOE basis for the year ended December 31,2015.Lease operating expense (“LOE”) on a per BOE basis for the year ended December 31, 2015, decreased 13 percent comparedto the same period in 2014. Our LOE is comprised of recurring LOE and workover expense. We experience volatility in our LOE as aresult of the impact industry activity has on service provider costs and seasonality in workover expense. Industry activity hassignificantly decreased in light of the low commodity price environment resulting in service providers lowering costs. For 2016, weexpect LOE on a per BOE basis to increase compared with 2015 due to the anticipated decline in year-over-year production exceedingany further decrease in service provider costs.Transportation costs on a per BOE basis for the year ended December 31, 2015, slightly decreased compared to the same periodin 2014. Our Eagle Ford shale assets have meaningfully higher transportation expense per unit of production compared to assets in ourother regions. Ongoing development of the Eagle Ford shale program has resulted in production from these assets becoming a largerportion of our total production, thereby increasing company-wide transportation expense per BOE over time. We expect transportationcosts on a per BOE basis to increase in 2016 compared with 2015 as a result of the change in our production mix due to the sale of ourMid-Continent assets in the second quarter of 2015.Production taxes on a per BOE basis for the year ended December 31, 2015, decreased 47 percent compared to the same periodin 2014 driven by the decrease in production revenues, as well as a decrease in our company-wide production tax rate as a result ofdivesting our Mid-Continent assets in the second quarter of 2015. We generally expect production tax expense to trend with oil, gas,and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourageoil and gas development can all impact or change the amount of production tax we recognize. General and administrative (“G&A”) expense on a per BOE basis for the year ended December 31, 2015, decreased 19 percentcompared to the same period in 2014 due to a six percent decrease in absolute G&A expense combined with a 16 percent increase inproduction. The decrease in absolute G&A expense is driven by lower short-term incentive compensation, as well as reducedheadcount and overhead cost in the second half of 2015 upon66closing our Tulsa office, partially offset by the $9.3 million of exit and disposal costs incurred related to this closure. A portion of ourG&A expense is linked to our profitability and cash flow, which are driven in large part by the realized commodity prices we receivefor our production. In 2016, we expect absolute G&A expense to decrease due to the reduced headcount resulting from the closure ofour Tulsa office being in effect for the entire year, as well as other general corporate cost saving initiatives. We expect G&A on a perBOE basis to be relatively flat in 2016 compared with 2015 as we anticipate the reduction in absolute G&A expense to be partiallyoffset by a decrease in production year-over-year.Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense, for the year endedDecember 31, 2015, increased three percent, on a per BOE basis, compared to the same period in 2014. Our DD&A rate fluctuates as aresult of impairments, planned and closed divestitures, and changes in the mix of our production and the underlying proved reservevolumes. The continued decrease in commodity prices resulted in a decrease in proved reserve volumes and consequently an increasedDD&A rate for the last half of 2015. In general, excluding the impact of commodity pricing in recent months, our DD&A rate hasdecreased over the past several years as assets with lower finding and development costs have become a larger portion of our totalproduction mix. Our finding and development costs have benefited from a general decrease in well costs and an increase in recoveriesper well, as well as from our outside-operated Eagle Ford shale program, where from 2011 through the first half of 2014 we addedreserves with minimal associated costs due to our carry with Mitsui E&P Texas LP (“Mitsui”). Please refer to Note 12 - Acquisition andDevelopment Agreement in Part II, Item 8 of this report for additional discussion on the Mitsui transaction. We expect DD&A expenseon a per BOE basis to increase in 2016 in line with the increase that occurred in the last half of 2015 as discussed above, partially offsetby reductions in the cost basis to be depleted due to proved properties that were impaired at December 31, 2015. Our DD&A rate willbe further impacted should commodity prices further decline in 2016, which could result in lower proved reserves and additionalimpairments. Please refer to Comparison of Financial Results and Trends between 2015 and 2014 and between 2014 and 2013 foradditional discussion. Please refer to the section Earnings per Share in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of thisreport for additional discussion on the types of shares included in our basic and diluted net income (loss) per common sharecalculations. We recorded a net loss for the year ended December 31, 2015. Consequently, our unvested RSUs and contingent PSUswere anti-dilutive for the year ended December 31, 2015, resulting in a decrease in the diluted weighted-average common sharesoutstanding for the year ended December 31, 2015, when compared to 2014.Comparison of Financial Results and Trends between 2015 and 2014 and between 2014 and 2013Oil, gas, and NGL productionThe following table presents the regional changes in our oil, gas, and NGL production, production revenues, and productioncosts between the years ended December 31, 2015, and 2014: Average Net DailyProduction Increase(Decrease) Production RevenueDecrease Production Costs Increase(Decrease) (MBOE/d) (in millions) (in millions)South Texas & Gulf Coast22.8 $(587.8) $54.0Rocky Mountain7.2 (230.5) (8.2)Permian(0.2) (98.8) (16.6)Mid-Continent (1)(4.9) (64.5) (21.5)Total24.9 $(981.6) $7.7___________________________________________(1) We divested our Mid-Continent assets in the second quarter of 2015.67Our 16 percent increase in equivalent production volumes from 2014 to 2015 is offset by a 48 percent decrease in realized priceon a per BOE basis, resulting in a 40 percent decrease in oil, gas, and NGL production revenue between the two periods. Please refer tothe caption Oil, gas, and NGL production expense below for discussion on the reasons for the change in production costs from 2014 to2015.The following table presents the regional changes in our oil, gas, and NGL production, production revenues, and productioncosts between the years ended December 31, 2014, and 2013: Average Net DailyProduction Increase(Decrease) Production RevenueIncrease (Decrease) Production Costs Increase(Decrease) (MBOE/d) (in millions) (in millions)South Texas & Gulf Coast25.5 $359.1 $104.3Rocky Mountain3.6 40.6 31.0Permian1.0 7.2 (0.5)Mid-Continent(11.5) (125.0) (15.9)Total18.6 $281.9 $118.9The significant production growth in our Eagle Ford shale program from 2013 to 2014 far exceeded the production decrease inour Mid-Continent region, which resulted from the divestiture of our assets in the Anadarko Basin in December 2013. A 14 percentincrease in production from 2013 to 2014 on an equivalent basis combined with a one percent decrease in realized price per BOEresulted in a 13 percent increase in revenue between the two periods. Please refer to the caption Oil, gas, and NGL production expensebelow for discussion on the reasons for the change in production costs from 2013 to 2014.Please refer to A year-to-year overview of selected production and financial information, including trends above for realizedprices received before the effects of derivative settlements for the years ended December 31, 2015, 2014, and 2013, and discussion oftrends on a per BOE basis.Net gain on divestiture activityThe following table presents our net gain on divestiture activity for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Net gain on divestiture activity$43.0 $0.6 $28.0The net gain on divestiture activity recorded for the year ended December 31, 2015, is due to the $108.4 million net gainrecorded on the sale of our Mid-Continent assets in the second quarter, partially offset by the write-down to fair value of certain otherassets held for sale and subsequently divested during 2015.The minimal net gain on divestiture activity recorded for the year ended December 31, 2014, is due to the $26.9 million gainrealized on the sale of non-strategic properties in the Williston Basin in our Rocky Mountain region during the second quarter of 2014,which was mostly offset by write-downs to fair value recorded on other unrelated assets held for sale.The net gain on divestiture activity recorded for the year ended December 31, 2013, is due to the net gains recorded on thedivestitures of certain assets in our Mid-Continent and Rocky Mountain regions of $25.3 million and $13.2 million, respectively,slightly offset by a $7.0 million loss recorded on the divestiture of non-strategic assets in our Permian region.68Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II, Item 8 of this report for additionaldiscussion.Marketed gas system revenue and expenseThe following table presents our marketed gas system revenue and expense for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Marketed gas system revenue$9.5 $24.9 $60.0Marketed gas system expense$13.9 $24.5 $57.6Marketed gas system revenue decreased $15.4 million from 2014 to 2015. Concurrent with the decrease in marketed gas systemrevenue, marketed gas system expense decreased $10.5 million from 2014 to 2015. This decrease was due to the sale of our Mid-Continent gas assets in the second quarter of 2015, which eliminated all marketed gas volumes and thus all future marketed gas activity.Marketed gas system revenue decreased $35.1 million from 2013 to 2014. Concurrent with the decrease in marketed gas systemrevenue, marketed gas system expense decreased $33.2 million from 2013 to 2014. The decrease occurred as a result of the divestitureof our assets in the Anadarko Basin in December 2013.Other operating revenuesThe following table presents our other operating revenues for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Other operating revenues$4.5 $15.2 $5.8Other operating revenues for the year ended December 31, 2014, included a $10.7 million gain recorded in the second quarterof 2014 related to our settlement with Endeavour Operating Corporation (“Endeavour”), in which we, our working interest partners, andEndeavour agreed to mutually release all claims and dismiss certain litigation in exchange for certain cash payments and otherconsideration. This settlement gain is the primary cause of the $10.7 million decrease from 2014 to 2015 and the $9.4 million increasefrom 2013 to 2014, as there was no additional significant other operating revenue activity recorded for the years ended December 31,2015, 2014, or 2013.Oil, gas, and NGL production expenseThe following table presents our oil, gas, and NGL production expense for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Oil, gas, and NGL production expense$723.6 $715.9 $597.0Total production costs increased $7.7 million, or one percent, from 2014 to 2015, primarily due to a 16 percent increase in netequivalent production volumes and a 15 percent increase in transportation expense resulting69from the continued development of our Eagle Ford shale program, largely offset by lower service provider costs and decreasedproduction taxes due to lower commodity prices. Please refer to the caption A year-to-year overview of selected production andfinancial information, including trends above for discussion of production costs on a per BOE basis.Total production costs increased $118.9 million, or 20 percent, from 2013 to 2014 primarily due to a 14 percent increase inproduction volumes on a per BOE basis, as well as an overall increase in transportation costs in our South Texas & Gulf Coast region.Depletion, depreciation, amortization, and asset retirement obligation liability accretionThe following table presents our DD&A expense for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Depletion, depreciation, amortization, and asset retirementobligation liability accretion$921.0 $767.5 $822.9DD&A expense increased 20 percent in 2015 compared with 2014, primarily due to the increase in production volumes andDD&A rate in 2015, partially offset by our Mid-Continent assets held for sale in the beginning of 2015 and sold in the second quarter.Please refer to the caption A year-to-year overview of selected production and financial information, including trends above fordiscussion of DD&A expense on a per BOE basis.DD&A expense decreased seven percent in 2014 compared with 2013, primarily due to an 18 percent decrease in the DD&Arate in 2014 driven largely by lower finding and development costs, partially offset by the 14 percent increase in production volumes.ExplorationThe components of exploration expense are summarized as follows: For the Years Ended December 31, 2015 2014 2013Summary of Exploration Expense(in millions)Geological and geophysical expenses$7.5 $11.4 $4.3Exploratory dry hole36.6 44.4 5.8Overhead and other expenses76.5 74.1 64.0Total$120.6 $129.9 $74.1Exploration expense for 2015 decreased seven percent compared with 2014 mainly due to decreases in exploratory dry holeexpense and geological and geophysical (“G&G”) expenses in 2015. During 2015, we expensed one exploratory dry hole in our RockyMountain region and three lower cost non-Eagle Ford exploratory dry holes in our South Texas & Gulf Coast region, compared to threehigher cost exploratory non-Eagle Ford dry holes expensed in our South Texas & Gulf Coast region in 2014. An exploratory projectresulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of explorationexpense we record. During the first quarter of 2014, we performed a seismic study in our Powder River Basin program, which resultedin increased G&G expenses in 2014 compared to 2015 and 2013.70Exploration expense for 2014 increased 75 percent compared with the same period in 2013 mainly due to an increase inexploratory dry hole expense and G&G expense, as discussed above, in addition to higher exploration overhead.Impairment of proved properties and abandonment and impairment of unproved propertiesThe following table presents our impairment of proved properties expense and abandonment and impairment of unprovedproperties expense for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Impairment of proved properties$468.7 $84.5 $172.6Abandonment and impairment of unproved properties$78.6 $75.6 $46.1Proved and unproved property impairments recorded in 2015 were due to continued commodity price declines, largelyimpacting our Powder River Basin program and certain legacy and non-core assets, as well as our decision to reduce capital invested inthe development of our east Texas exploration program in light of the sustained, low commodity price environment. Commodity pricessignificantly declined subsequent to the filing date of our September 30, 2015 Quarterly Report on Form 10-Q resulting in additionalimpairments of proved and unproved properties in the fourth quarter of 2015 totaling $398.8 million. Any amount of futureimpairments is difficult to predict. If commodity prices remain at levels near those as of January 31, 2016, we would expect to incurimpairments in the first quarter of 2016 of up to approximately $250 million. If commodity prices deteriorate further, additionalimpairments in future periods could occur. In addition to future commodity price declines, changes in drilling plans, downwardengineering revisions, or unsuccessful exploration efforts may result in additional proved and unproved property impairments.Proved and unproved property impairments recorded in 2014 were due to the significant decline in commodity prices in late2014 resulting in changes in our drilling plans and the abandonment of certain acreage, as well as recognition of the outcomes ofexploration and delineation wells in certain prospects in our South Texas & Gulf Coast and Permian regions.Proved and unproved property impairments recorded in 2013 were a result of negative engineering revisions on ourMississippian limestone assets in our Permian region at the end of the year, the commencement of a plugging and abandonmentprogram of dry gas assets in the Olmos interval in our South Texas & Gulf Coast region, and our decision to no longer pursue thedevelopment of certain under-performing assets during the year.Impairment of other property and equipmentThe following table presents our impairment of other property and equipment for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Impairment of other property and equipment$49.4 $— $—We impaired our gas gathering system assets in our east Texas program during the year ended December 31, 2015, inconjunction with the impairment of the associated proved and unproved properties resulting from our decision not to allocate additionalcapital to the program in light of sustained low commodity prices. We did not record impairments of other property and equipment forthe years ended December 31, 2014, or 2013.71General and administrativeThe following table presents our general and administrative expense for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)General and administrative$157.7 $167.1 $149.6G&A expense decreased $9.4 million, or six percent, from 2014 to 2015 due to lower short-term incentive compensation andreduced headcount and overhead costs resulting from the closing of our Tulsa office in the beginning of the third quarter of 2015.Included in G&A expense for the year ended December 31, 2015, is $9.3 million of exit and disposal costs related to the closure of ourTulsa office. Please refer to the caption A year-to-year overview of selected production and financial information, including trendsabove for discussion of G&A costs on a per BOE basis.G&A expense increased $17.6 million from 2013 to 2014 due primarily to an increase in employee headcount during 2014,which resulted in increased base compensation, benefits, and general office expenses.Change in Net Profits Plan liabilityThe following table presents the change in our Net Profits Plan liability for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Change in Net Profits Plan liability$(19.5) $(29.8) $(21.8)This non-cash benefit generally relates to the change in the estimated value of the associated liability between the reportingperiods resulting from settlements made or accrued during the period and changes in assumptions used for production rates, reservequantities, commodity pricing, discount rates, and production costs. The non-cash benefit for 2015 and 2014 is a result of a 72 percentand 52 percent respective decrease in the corresponding liability, which is a result of the continued decline in commodity prices andcash payments made or accrued under the plan. For 2015 and 2014, these cash payments included $3.8 million and $8.3 million,respectively, related to proceeds received from asset divestitures. The non-cash benefit for 2013 is due to cash payments made oraccrued under the plan, of which $10.3 million related to divestiture proceeds, slightly offset by an increase in the correspondingliability. We generally expect the change in our Net Profits Plan liability to correlate with fluctuations in commodity prices.Derivative gainThe following table presents our derivative gain for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Derivative gain$(408.8) $(583.3) $(3.1)72We recognized a derivative gain of $408.8 million for the year ended December 31, 2015, consisting of a $512.6 million gainrelated to settled contracts, partially offset by a $103.7 million decrease in the fair value of commodity derivative contracts during theperiod. The decrease in the fair value of commodity derivative contracts is related to the settlement of our 2015 contracts, largely offsetby an increase in the fair value of remaining contracts as of December 31, 2015, due to the continued decline in forward commoditystrip prices. This compares to a net derivative gain of $583.3 million for the same period in 2014, which consists of a $12.6 million gainon settlements and a $570.7 million increase in the fair value of commodity derivative contracts during the period. Forward commoditystrip prices declined at the end of 2014 and continued to decline throughout 2015, resulting in a significant gain on commodityderivative contracts settled in 2015 and a favorable mark-to-market adjustment on our commodity derivative contracts remaining atDecember 31, 2015.As noted above, commodity strip pricing declined at the end of 2014, resulting in a significant increase in the fair value of ourcommodity derivative contracts at December 31, 2014. This compared to a derivative gain of $3.1 million for the year endedDecember 31, 2013, which consisted of a $22.1 million gain on settlements and a $19.0 million decrease in the fair value of commodityderivative contracts during the period.Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.Other operating expensesThe following table presents our other operating expenses for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Other operating expenses$30.6 $4.7 $30.1Other operating expenses increased approximately $26.0 million from 2014 to 2015. The increase is primarily due to $13.7million of expense related to the early termination of drilling rig contracts or fees incurred on rigs placed on standby, $5.3 million ofexpense related to estimated claims for payment of royalties on certain Federal and Indian leases, as well as a $4.1 million materialsinventory write-down during 2015.Other operating expenses decreased $25.4 million from 2013 to 2014. In 2013, other operating expenses included $23.1 millionof expenses related to an agreed clarification concerning royalty payment provisions of various leases on certain South Texas & GulfCoast acreage.Loss on extinguishment of debtThe following table presents our loss on extinguishment of debt for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions)Loss on extinguishment of debt$(16.6) $— $—For the year ended December 31, 2015, we recorded a $16.6 million loss on the early extinguishment of our 2019 Notes, whichincludes approximately $12.5 million associated with the premium paid for the tender offer and redemption of the notes andapproximately $4.1 million for the acceleration of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in PartII, Item 8 of this report for additional information.73Income tax (expense) benefitThe following table presents our income tax (expense) benefit for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in millions, except tax rate)Income tax (expense) benefit$275.2 $(398.6) $(107.7)Effective tax rate38.1% 37.4% 38.6%The increase in the effective tax rate in 2015 compared to 2014 resulted from a tax benefit effect of Oklahoma permanent taxbenefits, enacted state rate changes in Texas and North Dakota, and claimed research and development (“R&D”) credits added to thebenefit created by a pre-tax loss recorded for the year ended December 31, 2015. Please refer to Note 4 - Income Taxes in Part II, Item 8of this report for further discussion.The increase in income tax expense for the year ended December 31, 2014, generally trends with the increase in pre-tax netincome. The net decrease in the effective tax rate from 2013 to 2014 is partially attributable to our 2013 Anadarko Basin divestiture,which caused a decrease in the composition of our blended state tax rate for future years, offset by an increase in our valuationallowance on state net operating losses in 2014. Overview of Liquidity and Capital ResourcesBased on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute ourbusiness plan for the foreseeable future. We continue to manage the duration and level of our drilling and completion servicecommitments to maintain the flexibility to adjust our activity and capital expenditures in periods of prolonged weak commodity pricesor to respond should commodity prices recover.Sources of cashWe currently expect our 2016 capital program to be primarily funded by cash flows from operations with any remaining cashneeds to be funded by borrowings under our credit facility. Although we anticipate that cash flows from these sources will be sufficientto fund our expected 2016 capital program, we may also elect to access the capital markets, depending on prevailing market conditions,as well as divest additional non-strategic oil and gas properties to provide additional sources of funding. From time to time, we mayenter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or development programs.Our credit ratings were recently downgraded by two major rating agencies. These downgrades and any future downgrades may make itmore difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be impacted by the general conditionof the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and ourindustry. We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of ourrealized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price riskmanagement program. During 2015, cash received from the settlement of commodity derivative contracts provided a significantpositive source of cash, which is reflected in net cash provided by operating activities on our consolidated statements of cash flows. Thefair value of our commodity derivative contracts was a net asset of $488.4 million at December 31, 2015, of which $367.7 millionrelates to contracts expected to settle in 2016. As our derivative contracts settle in future periods, and if commodity prices remain atcurrent levels or further decline, our future cash flow from operations will be negatively impacted. Please refer to Note 10 – DerivativeFinancial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contractscurrently in place and the timing of settlement of those contracts. There is additional discussion in the referenced note regarding certaincommodity derivative contracts restructured subsequent to December 31, 2015, that effectively increased the natural gas volume swapswe have in place in 2017 and eliminated the natural gas volume swaps in place in 2018 and 2019. Decreases in commodity prices havelimited our industry’s access to capital markets. The borrowing base under our74credit facility could be reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt. SeeCredit facility below for a discussion of our most recent borrowing base redetermination and our anticipated borrowing base reductionin 2016.In the second quarter of 2015, we issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025. Weused the net proceeds of $491.0 million for the tender and redemption of the $350.0 million principal amount of our 2019 Notes, aswell as to repay outstanding borrowings under our credit facility and for general corporate purposes.Proposals to reform the Internal Revenue Code (“IRC”), which include eliminating or reducing current tax deductions forintangible drilling costs, depreciation of equipment acquisition costs, the domestic production activities deduction, percentagedepletion, and other deductions which reduce our taxable income, continue to circulate. We expect that future legislation modifying oreliminating these deductions would reduce net operating cash flows over time, thereby reducing funding available for our explorationand development capital programs, as well as funding available to our peers in the industry for similar programs. If enacted, thesereductions in available deductions could have a significant adverse effect on drilling in the United States for a number of years.Credit facilityOur Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) provides a maximum loan amount of$2.5 billion, current aggregate lender commitments of $1.5 billion, and a maturity date of December 10, 2019. Our borrowing base issubject to regular semi-annual redeterminations. Effective as of October 7, 2015, our lenders decreased the borrowing base to $2.0billion from $2.4 billion, which was primarily a result of the sale of our Mid-Continent assets, and adjustments consistent with lowercommodity prices. The borrowing base redetermination process under the credit facility considers the value of our proved oil and gasproperties and our commodity derivative contracts, as determined by the lender group. We expect an additional reduction in ourborrowing base in the first half of 2016 due to the decrease in our proved reserves that we reported as of December 31, 2015, resultingfrom the continued decline in commodity prices. We do not expect to be negatively impacted by this anticipated borrowing basereduction, as we currently plan to spend within adjusted EBITDAX during 2016 and believe the revised borrowing base amount will besufficient to meet our anticipated liquidity and operating needs. No individual bank participating in our credit facility represents morethan 10 percent of the lender commitments under the credit facility. Borrowings under our credit facility are secured by mortgages onassets having a value equal to at least 75 percent of the total value of our proved oil and gas properties. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion as well as the presentation of the outstanding balance, total amountof letters of credit, and available borrowing capacity under our credit facility as of February 17, 2016, December 31, 2015, andDecember 31, 2014. We are subject to customary covenants under our credit facility, including limitations on dividend payments and requirements tomaintain certain financial ratios, which include debt to adjusted EBITDAX, as defined by our Credit Agreement as the ratio of debt to12-month trailing adjusted EBITDAX, of less than 4.0 and an adjusted current ratio, as defined by our Credit Agreement, of no lessthan 1.0. Please refer to the caption Non-GAAP Financial Measures below. As of December 31, 2015, our debt to EBITDAX ratio andadjusted current ratio were 2.3 and 4.8, respectively. As of the filing date of this report, we are in compliance with all financial and non-financial covenants under our credit facility.75Our daily weighted-average credit facility debt balance was approximately $253.7 million and $86.6 million for the years endedDecember 31, 2015, and 2014, respectively. Despite the decrease in our net operating cash flows for the year ended December 31,2015, resulting from the continued decline in commodity prices, we were able to limit our credit facility borrowings through divestitureproceeds, primarily from the sale of our Mid-Continent assets, and the issuance of our 2025 Notes in the second quarter of 2015. Ourdaily weighted-average credit facility debt balance was lower throughout 2014 as a result of proceeds received from propertydivestitures in the fourth quarter of 2013, as well the proceeds from our 2022 Notes being used to reduce our credit facility balance inthe fourth quarter of 2014. Cash flows provided by our operating activities, proceeds received from divestitures of properties and debtissuances, and the amount of our capital expenditures all impact the amount we have borrowed under our credit facility.Weighted-average interest ratesOur weighted-average interest rates include paid and accrued interest, fees on the unused portion of the credit facility’saggregate commitment amount, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-averageborrowing rates include paid and accrued interest only.The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years endedDecember 31, 2015, 2014, and 2013. For the Years Ended December 31, 2015 2014 2013Weighted-average interest rate6.0% 6.5% 6.3%Weighted-average borrowing rate5.5% 5.9% 5.7%Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2015, 2014, and2013, have been impacted by the timing of Senior Notes issuances and redemption, the average balance on our revolving credit facility,and the fees paid on the unused portion of our aggregate commitment. The rates disclosed in the above table for the year endedDecember 31, 2015, do not reflect the approximate $12.5 million premium paid for the tender offer and redemption of the 2019 Notesor the approximate $4.1 million of unamortized deferred financing costs expensed upon extinguishment of these notes during thesecond quarter of 2015. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional discussion.Uses of cashWe use cash for the acquisition, exploration, and development of oil and gas properties and for the payment of operating andgeneral and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the acquisition,exploration, and development of oil and gas properties are the primary use of our capital resources. During 2015, we spent $1.5 billionin capital expenditures and in acquiring proved and unproved oil and gas properties. These amounts differ from the costs incurredamounts, which are accrual-based and include asset retirement obligation, G&G, and exploration overhead amounts.The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and sizeof acquisition opportunities, our cash flows from operating, investing, and financing activities, and our ability to assimilate acquisitionsand execute our drilling program. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability ofcapital, and the timing and results of our operated and non-operated exploration and development activities may lead to changes infunding requirements for future development. We periodically review our capital expenditure budget to assess changes in current andprojected cash flows, acquisition and divestiture activities, debt requirements, and other factors.76We may from time to time repurchase certain amounts of our outstanding debt securities for cash and/or through exchanges forother securities. Such repurchases or exchanges may be made in open market transactions, privately negotiated transactions, orotherwise. Any such repurchases or exchanges will depend on prevailing market conditions, our liquidity requirements, contractualrestrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.Repurchases or exchanges are reviewed as part of the allocation of our capital. During the second quarter of 2015, we conducted atender offer and redeemed our 2019 Notes. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additionaldiscussion.As of the filing date of this report, we could repurchase up to 3,072,184 shares of our common stock under our stockrepurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the openmarket, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our creditfacility, the indentures governing our Senior Notes, compliance with securities laws, and the terms and provisions of our stockrepurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During 2015, wedid not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares.During 2015, we paid $6.8 million in dividends to our stockholders, which constitutes a dividend of $0.10 per share. Ourintention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition,credit facility and other covenants, and other factors which could arise. The payment and amount of future dividends remains at thediscretion of our Board of Directors. Analysis of cash flow changes between 2015 and 2014 and between 2014 and 2013The following tables present changes in cash flows between the years ended December 31, 2015, 2014, and 2013, for ouroperating, investing, and financing activities. The analysis following each table should be read in conjunction with our consolidatedstatements of cash flows in Part II, Item 8 of this report.Operating Activities For the Years EndedDecember 31, Amount Change Between Percent Change Between 2015 2014 2013 2015/2014 2014/2013 2015/2014 2014/2013 (in millions) Net cash providedby operatingactivities $978.4 $1,456.6 $1,338.5 $(478.2) $118.1 (33)% 9%Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, includingderivative cash settlements, decreased $366.1 million, or 18 percent, to $1.7 billion for the year ended December 31, 2015, comparedwith the same period in 2014. Cash paid for LOE increased $22.2 million, or 10 percent, to $252.5 million in 2015 compared with thesame period in 2014 due primarily to a 16 percent increase in production volumes, partially offset by a reduction in service providercosts. Cash paid for interest, net of capitalized interest, increased $37.8 million during 2015 compared to 2014 due to making, in 2015,the first interest payment on our 2022 Notes issued at the end of 2014. Additionally, we paid approximately $12.5 million associatedwith the premium for the tender offer and redemption of the 2019 Notes.77Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, includingderivative cash settlements, increased $256.0 million, or 14 percent, to $2.0 billion for the year ended December 31, 2014, compared to2013. Cash paid for lease operating expenses in 2014 increased $20.6 million, or nine percent, from 2013. These increases wereprimarily the result of a 14 percent increase in production volumes. Cash paid for interest, net of capitalized interest, increased $18.4million during 2014 compared to 2013 due to making, in 2014, the first interest payment on our 2024 Notes issued in 2013.Additionally, cash bonuses paid in 2014 for the 2013 performance year were $41.8 million compared to $16.3 million paid in 2013 forthe 2012 performance year. These changes are offset by a decrease in other operating working capital in 2014.Investing Activities For the Years EndedDecember 31, Amount Change Between Percent Change Between 2015 2014 2013 2015/2014 2014/2013 2015/2014 2014/2013 (in millions) Net cash used ininvesting activities $(1,144.6) $(2,478.7) $(1,192.9) $1,334.1 $(1,285.8) (54)% 108%Capital expenditures in 2015 decreased $481.2 million, or 24 percent, compared to 2014. Drilling capital incurred decreasedapproximately 38 percent in 2015 compared to 2014 as a result of reduced operated and non-operated rig count and lower serviceprovider costs. Partially offsetting this decrease in capital activity was our payment, in 2015, of a significant amount of accruedpayables at year-end 2014. Additionally, we did not have significant acquisition activity during 2015, whereas we acquired $544.6million of proved and unproved properties in our Gooseneck prospect area and in the Powder River Basin during 2014. Net proceedsfrom the sale of oil and gas properties increased $314.1 million in 2015 compared to 2014 due primarily to the divestiture of ourremaining Mid-Continent assets during the second quarter of 2015.Capital expenditures in 2014 increased $421.3 million, or 27 percent, compared to 2013 due primarily to increased spending inour Eagle Ford shale and Bakken/Three Forks programs. As discussed above, we acquired proved and unproved properties in ourGooseneck prospect area and in the Powder River Basin in 2014 that resulted in an increase in acquisition costs of $483.0 million whencompared to 2013. Net proceeds from the sale of oil and gas properties in 2014 decreased $381.0 million compared to 2013 dueprimarily to the sale of our Anadarko Basin assets in the fourth quarter of 2013.Financing Activities For the Years EndedDecember 31, Amount Change Between Percent Change Between 2015 2014 2013 2015/2014 2014/2013 2015/2014 2014/2013 (in millions) Net cash providedby financingactivities $166.2 $740.0 $130.7 $(573.8) $609.3 (78)% 466%We received $491.0 million of net proceeds from the issuance of our 2025 Notes in the second quarter of 2015. These proceedswere primarily used for the tender and redemption of the principal amount of $350.0 million of our 2019 Notes. See the OperatingActivities section above for discussion of the associated premium paid. In 2014, we received $590.0 million of net proceeds from theissuance of our 2022 Notes. We had net borrowings under our credit facility of $36.0 million during the year ended December 31,2015, compared with net borrowings of $166.0 million in 2014.78We received $590.0 million of net proceeds from the issuance of our 2022 Notes in 2014, compared with $490.2 million of netproceeds from the issuance of our 2024 Notes in 2013. These proceeds were used to repay outstanding borrowings under our creditfacility and for general corporate purposes. We had net borrowings under our credit facility of $166.0 million during 2014 comparedwith net payments of $340.0 million during 2013.Interest Rate RiskWe are exposed to market risk due to the floating interest rate on our revolving credit facility. Our Credit Agreement allows usto fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To theextent that the interest rate is fixed, interest rate changes will affect the credit facility’s fair market value, but will not impact results ofoperations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will notaffect the fair market value, but will impact future results of operations and cash flows. Changes in interest rates do not impact theamount of interest we pay on our fixed-rate Senior Notes, but can impact their fair market values. As of December 31, 2015, our fixed-rate debt and floating-rate debt outstanding totaled $2.35 billion and $202.0 million, respectively. The carrying amount of our floating-rate debt at December 31, 2015, approximates its fair value. Assuming a constant floating-rate debt level of $202.0 million, the before-tax cash flow impact resulting from a 100 basis point change would be $2.0 million over a 12-month period. Please refer to Note 11 -Fair Value Measurements in Part II, Item 8 of this report for additional discussion on the fair value of our Senior Notes.Commodity Price RiskThe prices we receive for our oil, gas, and NGL production directly impact our revenue, overall profitability, access to capital,and future rate of growth. Oil, gas, and NGL prices are subject to wide fluctuations in response to changes in supply and demand andother factors. The markets for oil, gas, and NGLs have been volatile, especially over the last year, and these markets will likelycontinue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Basedon our 2015 production, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivativesettlements, would have reduced our oil, gas, and NGL production revenues by approximately $79.7 million, $44.7 million, and $25.6million, respectively.79We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. The fair valuesof our commodity derivative contracts are largely determined by estimates of the forward curves of the relevant price indices. AtDecember 31, 2015, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodityderivative instruments would have changed our net asset positions by approximately $23 million, $46 million, and $14 million,respectively.Schedule of Contractual ObligationsThe following table summarizes our contractual obligations at December 31, 2015, for the periods specified (in millions):Contractual Obligations Total Less than 1year 1-3 years 3-5 years More than 5yearsLong-term debt (1) $2,552.0 $— $— $202.0 $2,350.0Interest payments (2) 1,101.3 146.9 293.9 285.1 375.4Delivery commitments (3) 864.0 87.4 242.8 269.1 264.7Operating leases and contracts (3) 100.4 45.3 16.8 14.9 23.4Asset retirement obligations (4) 201.0 12.4 45.0 10.8 132.8Other (5) 47.2 9.2 14.9 13.5 9.6Total $4,865.9 $301.2 $613.4 $795.4 $3,155.9____________________________________________(1) Long-term debt consists of our Senior Notes and the outstanding balance under our long-term revolving credit facility, and assumes no principalrepayment until the due dates of the instruments. The actual payments under our revolving credit facility may vary significantly.(2) Interest payments on our Senior Notes are estimated assuming no principal repayment until the due dates of the instruments. Interest payments on ourcredit facility have been estimated using the rate applicable to the balance on our credit facility as of December 31, 2015, and assume no futureborrowings or repayments until the December 10, 2019, due date. The actual interest payments on our Senior Notes and credit facility may varysignificantly.(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, and transportation throughput commitments.(4)Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on ouraccompanying consolidated balance sheets as of December 31, 2015. The timing and amount of the ultimate settlement of these obligations is unknownand can be impacted by economic factors, a change in development plans, and federal and state regulations. Inactive wells as of December 31, 2015, areshown as an obligation in 2016 due to the substantial uncertainty on the timing of plugging or re-entering these shut-in or temporarily abandoned wells.Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations.(5)The majority of the amount shown relates to the unfunded portion of our estimated pension liability of $36.8 million, for which we have estimated thetiming of future payments based on historical annual contribution amounts. We expect to make contributions to our pension plan in 2016 of $5.8million. Other amounts include the undiscounted forecasted payments for the Net Profits Plan. Please refer to Note 7 – Compensation Plans and Note 11 -Fair Value Measurements in Part II, Item 8 of this report for additional discussion regarding our Net Profits Plan liability.Off-balance Sheet ArrangementsAs part of our ongoing business, we have not participated in transactions that generate relationships with unconsolidated entitiesor financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would havebeen established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.We evaluate our transactions to determine if any variable interest entities exist. If it is determined that we are the primarybeneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involvedin any unconsolidated SPE transactions in 2015 or 2014.80Critical Accounting Policies and EstimatesOur discussion of financial condition and results of operations is based upon the information reported in our consolidatedfinancial statements. The preparation of these consolidated financial statements in conformity with accounting principles generallyaccepted in the United States (“GAAP”) requires us to make assumptions and estimates that affect the reported amounts of assets,liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our financial statements.We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under thecircumstances. Actual results may differ from the estimates we calculate due to changes in circumstances, global economics andpolitics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary ofSignificant Accounting Policies in Part II, Item 8 of this report. We have outlined below those policies identified as being critical to theunderstanding of our business and results of operations and that require the application of significant management judgment.Oil and gas reserve quantities. Our estimated proved reserve quantities and future net cash flows are critical to theunderstanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accountingestimates in our financial statements, including the calculations of depletion and impairment of proved oil and gas properties. Futurecash inflows and future production and development costs are determined by applying prices and costs, including transportation,quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to beproduced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. Forexample, the standardized measure calculations require a 10 percent discount rate to be applied. Although reserve estimates areinherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of establishedproducing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independentreservoir-evaluation consulting firm, to audit at least 80 percent of our total calculated proved reserve PV-10. We expect proved reserveestimates will change as additional information becomes available and as commodity prices and operating and capital costs change. Weevaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted inaccordance with GAAP for the impact of additions and dispositions. Changes in depletion or impairment calculations caused bychanges in reserve quantities or net cash flows are recorded in the period the reserve estimates change. Please refer to Supplemental Oiland Gas Information in Part II, Item 8 of this report.The following table presents information about proved reserve changes from period to period due to items we do not control,such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure onour part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves. Please refer toReserves included in Part I, Items 1 and 2 of this report for additional discussion. For the Years Ended December 31, 2015 2014 2013 MMBOE MMBOE MMBOE Change Change ChangeRevisions resulting from performance47.3 11.3 7.2Removal of proved undeveloped reserves nolonger in our development plan(79.4) (4.3) (2.8)Revisions resulting from price changes(116.5) 3.4 0.6Total(148.6) 10.4 5.0As previously noted, commodity prices are volatile, and estimates of reserves are inherently imprecise. Consequently, we expectto continue experiencing these types of changes. Please refer to additional reserves discussion above under Overview of the Company.81The following table reflects the estimated MMBOE change and percentage change to our total reported reserve volumes fromthe described hypothetical changes: For the Years Ended December 31, 2015 2014 2013 MMBOE Percentage MMBOE Percentage MMBOE Percentage Change Change Change Change Change Change10% decrease in SECpricing(107.6) (23)% (9.6) (2)% (9.8) (2)%10% decrease in provedundeveloped reserves(22.7) (5)% (26.1) (5)% (22.0) (5)%The table above solely reflects the impact of a 10 percent decrease in SEC pricing or decrease in proved undeveloped reservesand does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles, changes in futureservice or equipment costs, or related decreases in production taxes or transportation costs. Additional reserve information can be foundin the reserve table and discussion included in Items 1 and 2 of Part I of this report, and in Supplemental Oil and Gas Information ofPart II, Item 8 of this report.Successful efforts method of accounting. GAAP provides for two alternative methods for the oil and gas industry to use inaccounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and thesuccessful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set offacts will provide materially different financial statement results within a given year. We have chosen the successful efforts method ofaccounting for our oil and gas producing activities. A more detailed description is included in Note 1 - Summary of SignificantAccounting Policies of Part II, Item 8 of this report.Revenue recognition. Our revenue recognition policy is significant because revenue is a key component of our results ofoperations and our forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenueprimarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when our production is delivered to the purchaser, butpayment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determinedthat title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of productiondelivered to the purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, theirhistorical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis for these estimates. Variancesbetween our estimates and the actual amounts received are recorded in the month payment is received. A 10 percent change in our yearend revenue accrual would have impacted total operating revenues by approximately $6 million in 2015.Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with theabandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gaswells and our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimatethe cost, estimate the economic lives and timing of abandonment of our properties, estimate future inflation rates, and determine whatcredit-adjusted risk-free discount rate to use. The impact to the accompanying consolidated statements of operations from theseestimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our respectiveoil and gas properties. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.Impairment of oil and gas properties. Our proved oil and gas properties are recorded at cost. We evaluate our proved propertiesfor impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may haveoccurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to thecarrying amount of the oil and gas properties to82determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we willwrite down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are notlimited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and capitalexpenditures, and discount rates.Unproved oil and gas properties are assessed periodically for impairment on a prospect-by-prospect basis based on theremaining lease terms, drilling results, commodity price outlook, and future capital allocations. Unproved oil and gas properties areimpaired when we determine that the property will not be developed or the carrying value will not be realized.Please refer to Impairment of Proved and Unproved Properties in Note 1 - Summary of Significant Accounting Policies in PartII, Item 8 of this report for impairment results.Impairment of property and equipment. Our property and equipment is recorded at cost. We evaluate a long-lived asset, otherthan proved and unproved properties, when events or changes in circumstances indicate that its carrying value may be greater than itsundiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying value over its estimated fairvalue. We use an income valuation technique if there is not a market-observable price for the asset.Please refer to Impairment of Other Property and Equipment in Note 1 - Summary of Significant Accounting Policies in Part II,Item 8 of this report for impairment results.Derivatives and Hedging. We periodically enter into commodity derivative contracts to manage our exposure to oil, gas andNGL price volatility. The accounting treatment for the change in fair value of a derivative instrument is dependent upon whether or nota derivative instrument is designated as a cash flow hedge. Prior to January 1, 2011, we designated our commodity derivative contractsas cash flow hedges, for which unrealized changes in fair value were recorded to AOCL, to the extent the hedges were effective. As ofJanuary 1, 2011, we elected to de-designate all of our commodity derivative contracts that had been previously designated as cash flowhedges at December 31, 2010. As a result, subsequent to December 31, 2010, we recognize all gains and losses from changes incommodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCL. The estimated fair value ofour derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models,futures prices, volatility, time to maturity, and credit risk. The values we report in our financial statements change as these estimates arerevised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.Income taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and itscarrying amount in our financial statements. This difference will result in taxable income or deductions in future years when thereported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when theseevents may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns aregenerally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets andliabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital losscarryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report arerecorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery andliability settlement could have an impact on our results of operations. A one percent change in our effective tax rate would havechanged our calculated income tax benefit by approximately $7 million for the year ended December 31, 2015.Accounting MattersPlease refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant AccountingPolicies in Part II, Item 8 of this report for additional information on the recent adoption of new authoritative accounting guidance.83EnvironmentalWe believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate thatmaterial future expenditures will be required under the existing regulatory framework. However, environmental laws and regulationsare subject to frequent changes and we are unable to predict the impact that compliance with future laws or regulations, such as thosecurrently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production ofhydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, see RiskFactors – Risks Related to Our Business – Proposed federal and state legislative and regulatory initiatives relating to hydraulicfracturing could result in increased costs and additional operating restrictions or delays.Climate Change. In September 2015, the EPA proposed emission standards for methane and VOC for sources in the oil and gassector constructed or modified after September 1, 2015. The proposed rules expand the 2012 NSPS for VOC emissions from the oil andgas sector to include methane emissions. For sources not affected by the 2012 NSPS, the proposed rule imposes both VOC and methanestandards. In particular, the proposal would require methane reductions from centrifugal and reciprocating compressors, pneumaticpumps, fugitive emissions from well sites and compressor stations and equipment leaks at natural gas processing plants. The proposaldoes not extend to existing sources and the EPA has not indicated when it will propose existing source standards. Additionally, inJanuary of 2016, the BLM proposed additional rules designed to reduce methane venting and flaring from production wells, pneumaticcontrollers and storage tanks on federal and tribal lands, which are expected to be finalized in 2016.In June 2013, President Obama announced a Climate Action Plan designed to further reduce greenhouse gas emissions andprepare the nation for the physical effects that may occur as a result of climate change. The Plan targets methane reductions from the oiland gas sector as part of a comprehensive interagency methane strategy. On January 14, 2015, the Obama Administration announcedadditional steps to reduce methane emissions from the oil and gas sector by 40 to 45 percent by 2025. Pursuant to this commitment, inSeptember of 2015 the EPA proposed emission standards for methane and VOC for sources in the oil and gas sector constructed ormodified after September 1, 2015. The proposed rules expand the 2012 NSPS for VOC emissions from the oil and gas sector to includemethane emissions. For sources not affected by the 2012 NSPS, the proposed rule imposes both VOC and methane standards. Inparticular, the proposal would require methane reductions from centrifugal and reciprocating compressors, pneumatic pumps, fugitiveemissions from well sites and compressor stations and equipment leaks at natural gas processing plants. The proposal does not extendto existing sources and the EPA has not indicated when it will propose existing source standards. Additionally, in January of 2016, theBLM proposed additional rules designed to reduce methane venting and flaring from production wells, pneumatic controllers andstorage tanks on federal and tribal lands, which are expected to be finalized in 2016. In August of 2015, the EPA finalized existingsource performance standards as stringent state emission “goals.” The proposed standards focus on re-dispatching electricity from coal-fired units to natural gas combined cycle plants and renewables. In February 2016, however, the Supreme Court stayed these rulespending judicial review.In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhousegases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily throughthe planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most ofthese cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels,such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available forpurchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increasedoperating costs, such as costs to purchase and operate emissions control systems, to acquire84emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could alsoincrease the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation andregulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition, andresults of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gasesin the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severityof storms, droughts, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on ourfinancial condition and results of operations.In terms of opportunities, the regulation of greenhouse gas emissions and the introduction of alternative incentives, such asenhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example,although federal regulation and climate change legislation could reduce the overall demand for the oil and natural gas that we produce,the relative demand for natural gas may increase because the burning of natural gas produces lower levels of emissions than otherreadily available fossil fuels such as oil and coal. In addition, if renewable resources, such as wind or solar power become moreprevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if statesadopt low-carbon fuel standards, natural gas may become a more attractive transportation fuel. Approximately 45 and 46 percent of ourproduction on a BOE basis in 2015 and 2014, respectively, was natural gas. Market-based incentives for the capture and storage ofcarbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could also benefit us through the potential toobtain greenhouse gas emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.Non-GAAP Financial MeasuresAdjusted EBITDAX represents net income (loss) before interest expense, other non-operating income or expense, income taxes,depreciation, depletion, amortization, and accretion expense, exploration expense, impairments, non-cash stock-based compensationexpense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses on divestitures.Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that aregenerally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAPmeasure that is presented because we believe it provides useful additional information to investors and analysts, as a performancemeasure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We arealso subject to a financial covenant under our credit facility based on our debt to adjusted EBITDAX ratio. In addition, adjustedEBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendationsof companies in the oil and gas exploration and production industry, and many investors use the published research of industryresearch analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for netincome (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures preparedunder GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary amongcompanies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.85The following table provides reconciliations of our net income (loss) and net cash provided by operating activities to adjustedEBITDAX for the periods presented: For the Years Ended December 31, 2015 2014 2013 (in thousands)Net income (loss) (GAAP)$(447,710) $666,051 $170,935 Interest expense128,149 98,554 89,711 Other non-operating (income) expense, net(649) 2,561 (67) Income tax expense (benefit)(275,151) 398,648 107,676 Depletion, depreciation, amortization, and asset retirement obligation liabilityaccretion921,009 767,532 822,872 Exploration (1)113,158 122,577 65,888 Impairment of proved properties468,679 84,480 172,641 Abandonment and impairment of unproved properties78,643 75,638 46,105 Impairment of other property and equipment49,369 — — Stock-based compensation expense27,467 32,694 32,347 Derivative gain(408,831) (583,264) (3,080) Derivative settlement gain (2)512,566 12,615 22,062 Change in Net Profits Plan liability(19,525) (29,849) (21,842) Net gain on divestiture activity(43,031) (646) (27,974) Loss on extinguishment of debt16,578 — — Other, net4,054 — —Adjusted EBITDAX (Non-GAAP)1,124,775 1,647,591 1,477,274 Interest expense(128,149) (98,554) (89,711) Other non-operating income (expense), net649 (2,561) 67 Income tax (expense) benefit275,151 (398,648) (107,676) Exploration (1)(113,158) (122,577) (65,888) Exploratory dry hole expense36,612 44,427 5,846 Amortization of deferred financing costs7,710 6,146 5,390 Deferred income taxes(276,722) 397,780 105,555 Plugging and abandonment(7,496) (8,796) (9,946) Loss on extinguishment of debt(12,455) — — Other, net9,707 1,069 2,775 Changes in current assets and liabilities61,728 (9,302) 14,828Net cash provided by operating activities (GAAP)$978,352 $1,456,575 $1,338,514____________________________________________(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements ofoperations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements ofoperations for the component of stock-based compensation expense recorded to exploration expense.(2)Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include a $15.3 million gain and $5.6 million gain on the earlysettlement of futures contracts during the second quarter of 2015 and first quarter of 2014, respectively, as a result of divesting our Mid-Continent assets.86ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKThe information required by this item is provided under the captions Commodity Price Risk and Interest Rate Risk in Item 7above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place under Note 10 – DerivativeFinancial Instruments in Part II, Item 8 of this report and is incorporated herein by reference.87ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAReport of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of SM Energy Company and subsidiariesWe have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries as of December 31, 2015 and2014, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows foreach of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financialstatements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position ofSM Energy Company and subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cashflows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accountingprinciples.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), SMEnergy Company and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013framework), and our report dated February 24, 2016 expressed an unqualified opinion thereon./s/ Ernst & Young LLPDenver, ColoradoFebruary 24, 201688SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands, except share amounts) December 31, 2015 2014 ASSETS (as adjusted)Current assets: Cash and cash equivalents$18 $120Accounts receivable (note 2)134,124 322,630Derivative asset367,710 402,668Prepaid expenses and other17,137 19,625Total current assets518,989 745,043 Property and equipment (successful efforts method): Proved oil and gas properties7,606,405 7,348,436Less - accumulated depletion, depreciation, and amortization(3,481,836) (3,233,012)Unproved oil and gas properties284,538 532,498Wells in progress387,432 503,734Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $0and $22,482, respectively641 17,891Other property and equipment, net of accumulated depreciation of $32,956 and $37,079, respectively153,100 334,356Total property and equipment, net4,950,280 5,503,903 Noncurrent assets: Derivative asset120,701 189,540Other noncurrent assets31,673 44,659Total other noncurrent assets152,374 234,199Total Assets$5,621,643 $6,483,145 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued expenses (note 2)$302,517 $640,684Derivative liability8 —Deferred tax liability— 142,976Other current liabilities— 1,000Total current liabilities302,525 784,660 Noncurrent liabilities: Revolving credit facility202,000 166,000Senior Notes, net of unamortized deferred financing costs (note 5)2,315,970 2,166,445Asset retirement obligation137,525 120,867Net Profits Plan liability7,611 27,136Deferred income taxes758,279 891,681Derivative liability— 70Other noncurrent liabilities45,332 39,631Total noncurrent liabilities3,466,717 3,411,830 Commitments and contingencies (note 6) Stockholders’ equity: Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,075,700and 67,463,060 shares, respectively681 675Additional paid-in capital305,607 283,295Retained earnings1,559,515 2,013,997Accumulated other comprehensive loss(13,402) (11,312)Total stockholders’ equity1,852,401 2,286,655Total Liabilities and Stockholders’ Equity$5,621,643 $6,483,145The accompanying notes are an integral part of these consolidated financial statements.89SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per share amounts) For the Years EndedDecember 31, 2015 2014 2013Operating revenues: Oil, gas, and NGL production revenue$1,499,905 $2,481,544 $2,199,550Net gain on divestiture activity (note 3)43,031 646 27,974Marketed gas system revenue9,485 24,897 60,039Other operating revenues4,544 15,220 5,811Total operating revenues and other income1,556,965 2,522,307 2,293,374Operating expenses: Oil, gas, and NGL production expense723,633 715,878 597,045Depletion, depreciation, amortization, and asset retirement obligation liabilityaccretion921,009 767,532 822,872Exploration120,569 129,857 74,104Impairment of proved properties468,679 84,480 172,641Abandonment and impairment of unproved properties78,643 75,638 46,105Impairment of other property and equipment49,369 — —General and administrative157,668 167,103 149,551Change in Net Profits Plan liability(19,525) (29,849) (21,842)Derivative gain(408,831) (583,264) (3,080)Marketed gas system expense13,922 24,460 57,647Other operating expenses30,612 4,658 30,076Total operating expenses2,135,748 1,356,493 1,925,119Income (loss) from operations(578,783) 1,165,814 368,255Non-operating income (expense): Other, net649 (2,561) 67Interest expense(128,149) (98,554) (89,711)Loss on extinguishment of debt(16,578) — —Income (loss) before income taxes(722,861) 1,064,699 278,611Income tax (expense) benefit275,151 (398,648) (107,676)Net income (loss)$(447,710) $666,051 $170,935Basic weighted-average common shares outstanding67,723 67,230 66,615Diluted weighted-average common shares outstanding67,723 68,044 67,998Basic net income (loss) per common share$(6.61) $9.91 $2.57Diluted net income (loss) per common share$(6.61) $9.79 $2.51The accompanying notes are an integral part of these consolidated financial statements.90SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(in thousands) For the Years EndedDecember 31, 2015 2014 2013Net income (loss)$(447,710) $666,051 $170,935Other comprehensive income (loss), net of tax: Reclassification to earnings (1)— — 1,115 Pension liability adjustment (2)(2,090) (5,896) 2,483Total other comprehensive income (loss), net of tax(2,090) (5,896) 3,598Total comprehensive income (loss)$(449,800) $660,155 $174,533(1) Reclassification from accumulated other comprehensive loss related to de-designated hedges. Refer to Note 10 - Derivative Financial Instruments forfurther information.(2) Refer to Note 1 - Summary of Significant Accounting Policies for detail of the pension amount reclassified to general and administrative expense on theCompany’s consolidated statements of operations.The accompanying notes are an integral part of these consolidated financial statements.91SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY(in thousands, except share amounts) AdditionalPaid-inCapital Accumulated OtherComprehensive Loss TotalStockholders’Equity Common Stock Treasury Stock RetainedEarnings Shares Amount Shares Amount Balances, January 1, 201366,245,816 $662 $233,642 (50,581) $(1,221) $1,190,397 $(9,014) $1,414,466Net income— — — — — 170,935 — 170,935Other comprehensive income— — — — — — 3,598 3,598Cash dividends, $ 0.10 per share— — — — — (6,663) — (6,663)Issuance of common stock underEmployee Stock Purchase Plan77,427 1 3,671 — — — — 3,672Issuance of common stock uponvesting of RSUs and settlement ofPSUs, net of shares used for taxwithholdings526,852 5 (16,225) — — — — (16,220)Issuance of common stock uponstock option exercises228,758 3 3,183 — — — — 3,186Stock-based compensation expense— — 31,949 28,169 398 — — 32,347Other income tax benefit— — 1,500 — — — — 1,500Balances, December 31, 201367,078,853 $671 $257,720 (22,412) $(823) $1,354,669 $(5,416) $1,606,821Net income— — — — — 666,051 — 666,051Other comprehensive loss— — — — — — (5,896) (5,896)Cash dividends, $ 0.10 per share— — — — — (6,723) — (6,723)Issuance of common stock underEmployee Stock Purchase Plan83,136 1 4,060 — — — — 4,061Issuance of common stock uponvesting of RSUs and settlement ofPSUs, net of shares used for taxwithholdings256,718 3 (10,627) — — — — (10,624)Issuance of common stock uponstock option exercises39,088 — 816 — — — — 816Stock-based compensation expense5,265 — 31,871 22,412 823 — — 32,694Other income tax expense— — (545) — — — — (545)Balances, December 31, 201467,463,060 $675 $283,295 — $— $2,013,997 $(11,312) $2,286,655Net loss— — — — — (447,710) — (447,710)Other comprehensive loss— — — — — — (2,090) (2,090)Cash dividends, $ 0.10 per share— — — — — (6,772) — (6,772)Issuance of common stock underEmployee Stock Purchase Plan197,214 2 4,842 — — — — 4,844Issuance of common stock uponvesting of RSUs and settlement ofPSUs, net of shares used for taxwithholdings375,523 4 (8,682) — — — — (8,678)Stock-based compensation expense39,903 — 27,467 — — — — 27,467Other income tax expense— — (1,315) — — — — (1,315)Balances, December 31, 201568,075,700 $681 $305,607 — $— $1,559,515 $(13,402) $1,852,401The accompanying notes are an integral part of these consolidated financial statements.92SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) For the Years EndedDecember 31, 2015 2014 2013Cash flows from operating activities: Net income (loss)$(447,710) 666,051 170,935Adjustments to reconcile net income (loss) to net cash provided by operating activities: Net gain on divestiture activity(43,031) (646) (27,974)Depletion, depreciation, amortization, and asset retirement obligation liability accretion921,009 767,532 822,872Exploratory dry hole expense36,612 44,427 5,846Impairment of proved properties468,679 84,480 172,641Abandonment and impairment of unproved properties78,643 75,638 46,105Impairment of other property and equipment49,369 — —Stock-based compensation expense27,467 32,694 32,347Change in Net Profits Plan liability(19,525) (29,849) (21,842)Derivative gain(408,831) (583,264) (3,080)Derivative settlement gain512,566 12,615 22,062Amortization of deferred financing costs7,710 6,146 5,390Non-cash loss on extinguishment of debt4,123 — —Deferred income taxes(276,722) 397,780 105,555Plugging and abandonment(7,496) (8,796) (9,946)Other, net13,761 1,069 2,775Changes in current assets and liabilities: Accounts receivable140,200 24,088 (79,398)Prepaid expenses and other2,563 (1,822) 98Accounts payable and accrued expenses(86,267) 9,466 91,516Accrued derivative settlements5,232 (41,034) 2,612Net cash provided by operating activities978,352 1,456,575 1,338,514 Cash flows from investing activities: Net proceeds from the sale of oil and gas properties357,938 43,858 424,849Capital expenditures(1,493,608) (1,974,798) (1,553,536)Acquisition of proved and unproved oil and gas properties(7,984) (544,553) (61,603)Other, net(985) (3,256) (2,613)Net cash used in investing activities(1,144,639) (2,478,749) (1,192,903) Cash flows from financing activities: Proceeds from credit facility1,872,500 1,285,500 1,203,000Repayment of credit facility(1,836,500) (1,119,500) (1,543,000)Debt issuance costs related to credit facility— (3,388) (3,444)Net proceeds from Senior Notes490,951 589,991 490,185Repayment of Senior Notes(350,000) — —Proceeds from sale of common stock4,844 4,877 6,858Dividends paid(6,772) (6,723) (6,663)Net share settlement from issuance of stock awards(8,678) (10,624) (16,220)Other, net(160) (87) (5)Net cash provided by financing activities166,185 740,046 130,711 Net change in cash and cash equivalents(102) (282,128) 276,322Cash and cash equivalents at beginning of period120 282,248 5,926Cash and cash equivalents at end of period$18 $120 $282,248The accompanying notes are an integral part of these consolidated financial statements.93SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)Supplemental schedule of additional cash flow information and non-cash activities: For the Years EndedDecember 31, 2015 2014 2013 (in thousands)Cash paid for interest, net of capitalized interest$126,988 $89,145 $70,702 Net cash paid (refunded) for income taxes$1,630 $1,936 $(204)As of December 31, 2015, 2014, and 2013, $97.4 million, $357.2 million, and $217.8 million, respectively, of accrued capital expenditures wereincluded in accounts payable and accrued expenses in the Company’s consolidated balance sheets. These oil and gas property additions are reflected in netcash used in investing activities in the periods during which the payables are settled.During the second quarter of 2014 and the third quarter of 2013, the Company exchanged properties in its Rocky Mountain region with fair valuesof $6.2 million and $25.0 million, respectively. The amount of cash consideration paid at the respective closings for agreed upon adjustments is reflected inthe acquisition of proved and unproved oil and gas properties line item in the consolidated statements of cash flows.94SM ENERGY COMPANY AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote 1 – Summary of Significant Accounting PoliciesDescription of OperationsSM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and productionof crude oil and condensate, natural gas, and NGLs in onshore North America. Basis of PresentationThe accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiariesand have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Subsidiaries that theCompany does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are includedin other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accountsand transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Companyevaluated subsequent events after the balance sheet date of December 31, 2015, through the filing date of this report.Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanyingfinancial statements. Please refer to the caption Recently Issued Accounting Standards below for additional discussion of the change inpresentation of debt issuance costs on the accompanying balance sheets.Use of Estimates in the Preparation of Financial StatementsThe preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions thataffect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the dateof the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differfrom those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation,and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significantcomponent of the accompanying consolidated financial statements.Cash and Cash EquivalentsThe Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents.The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.Accounts ReceivableThe Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interestowners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability towithhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gasreceivables are collected within two months and the Company has had minimal bad debts.Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individualcompany and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company’sallowance for doubtful accounts as of December 31, 2015, totaled $1.1 million, primarily for receivables from joint interest owners. TheCompany had no allowance for doubtful accounts as of December 31, 2014.95Concentration of Credit Risk and Major CustomersThe Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which areconcentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. TheCompany does not believe the loss of any single purchaser would materially impact its operating results, as crude oil, natural gas, andNGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. During 2015 and2014, the Company had one major customer, which represented approximately 21 percent and 19 percent, respectively, of totalproduction revenue, which is discussed in the next paragraph. During 2015 and 2014, the Company also sold to four entities that areunder common ownership. In aggregate, these four entities represented approximately 10 percent and 14 percent of total productionrevenue in 2015 and 2014, respectively; however, none of these entities individually represented more than 10 percent of totalproduction revenue. Additionally, in 2015 the Company sold to three entities that are under common ownership, which in aggregaterepresented 11 percent of its total production revenue; however, none of these entities individually represented more than 10 percent ofthe Company’s total production revenue. During 2013, the Company had three major customers, which represented approximately 26percent, 16 percent, and 12 percent, respectively, of total production revenue.During the third quarter of 2013, the Company entered into various marketing agreements with a joint venture partner, wherebythe Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to eachcontract. While the Company’s joint venture partner is the first purchaser under these contracts, representing 21 percent and 19 percentof total production revenue in 2015 and 2014, respectively, the Company also shares with them the risk of non-performance by theircounterparty purchasers. Several of the Company’s joint venture partner’s counterparty purchasers under these contracts are also directpurchasers of products produced by the Company from other operated areas.The Company’s policy is to use the commodity affiliates of the lenders under its credit facility as its derivative counterparties,and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 counterparties meet bothof these requirements as of the filing date of this report.The Company has accounts in the following locations with a national bank: Denver, Colorado; Houston, Texas; Midland, Texas;and Billings, Montana. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at eachindividual institution.Oil and Gas Producing ActivitiesThe Company accounts for its oil and gas exploration and development costs using the successful efforts method. G&G costsare expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverablereserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. Theapplication of the successful efforts method of accounting requires management’s judgment to determine the proper designation ofwells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Oncea well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment.Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanyingstatements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful.DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, andabandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2015, and 2014, the estimatedsalvage value of the Company’s equipment was $29.7 million and $50.8 million, respectively.96Assets Held for SaleAny properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presentedon the accompanying balance sheets at the lower of carrying value or fair value less the cost to sell. For additional discussion on assetsheld for sale, please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions.Other Property and EquipmentOther property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and softwareare recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized.Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over theestimated useful lives of the assets, which range from three to 30 years, or the unit of output method where appropriate. When otherproperty and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.Internal Use Software Development CostsThe Company capitalizes certain software costs incurred during the application development stage. The applicationdevelopment stage generally includes software design, configuration, testing and installation activities. Training and maintenance costsare expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result inadditional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2015, and 2014, the Company has capitalized approximately $44.0million and $35.0 million, respectively, related to the development and implementation of accounting and operational software. Derivative Financial InstrumentsThe Company seeks to manage or reduce commodity price risk on its production by entering into derivative contracts. TheCompany seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts toOPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into which the Company’s gasproduction is sold. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments.Net Profits PlanThe Company records the estimated fair value of expected future payments to be made under the Net Profits Plan as anoncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liabilityinclude estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and advalorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculatingthe long-term liability are adjusted from period-to-period based on the most current information attributable to the underlyingassumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases ordecreases to expense in the current period as a separate line item in the accompanying statements of operations, as these changes areconsidered changes in estimates.The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation relatedto periodic operations are recognized as compensation expense and are included within general and administrative expense andexploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payableand accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with netcash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to theheading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements.97Asset Retirement ObligationsThe Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. Aliability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-livedasset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and gas properties inthe accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizesexpense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oiland gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations.Revenue RecognitionThe Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when theCompany’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date ofproduction. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of eachmonth, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. TheCompany uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot marketprices, quality and transportation differentials, and other factors as the basis for these estimates. The Company uses the sales method ofaccounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales areproportionate to the Company’s ownership in the property.Impairment of Proved and Unproved PropertiesProved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected futurediscounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows arecalculated on all proved reserves and risk adjusted probable and possible reserves using a discount rate and price forecasts thatmanagement believes are representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strippricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. Theprices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, afterwhich a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment isrecorded on unproved property when the Company determines that either the property will not be developed or the carrying value isnot realizable.The Company recorded $468.7 million, $84.5 million, and $172.6 million, of proved property impairment expense for the yearsended December 31, 2015, 2014, and 2013, respectively. The impairments of proved properties in 2015 were due to continuedcommodity price declines, largely impacting the Company’s Powder River Basin program and certain legacy and non-core assets in theRocky Mountain region, as well as the Company’s decision to reduce capital invested in the development of its east Texas explorationprogram in its South Texas & Gulf Coast region. The impairments of proved properties in 2014 were primarily a result of the significantdecline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects inthe Company’s South Texas & Gulf Coast and Permian regions. The impairments in 2013 primarily resulted from the write-down ofcertain Mississippian limestone assets in the Company’s Permian region due to negative engineering revisions, write-downs related toOlmos interval, dry gas assets in the South Texas & Gulf Coast region as a result of a plugging and abandonment program, and write-downs of certain underperforming assets due to the Company’s decision to no longer pursue the development of those assets.98For the years ended December 31, 2015, 2014, and 2013, the Company recorded expense related to the abandonment andimpairment of unproved properties of $78.6 million, $75.6 million, and $46.1 million, respectively. The Company’s abandonment andimpairment of unproved properties expense in 2015 and 2014 was primarily a result of lease expirations and acreage the Company nolonger intended to develop in light of changes in drilling plans in response to the continued decline in commodity prices. TheCompany’s abandonment and impairment of unproved properties expense in 2013 was mostly related to acreage the Company nolonger intended to develop in its Permian region.Impairment of Other Property and EquipmentA long-lived asset is evaluated for potential impairment whenever events or changes in circumstances indicate that its carryingvalue may be greater than its undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carryingvalue over its estimated fair value. The Company uses an income valuation technique if there is not a market-observable price for theasset.For the year ended December 31, 2015, the Company recorded a $49.4 million impairment charge on its gas gathering systemassets in east Texas, in conjunction with the impairment of the associated proved and unproved properties, resulting from theCompany’s decision to reduce capital spent in the program in light of sustained, low commodity prices. The Company did not have anyimpairments of other property and equipment for the years ended December 31, 2014, or 2013.Sales of Proved and Unproved PropertiesThe partial sale of proved property within an existing field is accounted for as normal retirement and no net gain or loss ondivestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale ofa partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity isrecognized in the accompanying statements of operations for all other sales of proved properties.The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimaterecovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales priceexceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanyingstatements of operations for all other sales of unproved property. For additional discussion, please refer to Note 3 – Divestitures, AssetsHeld for Sale, and Acquisitions.Stock-Based CompensationAt December 31, 2015, the Company had stock-based employee compensation plans that included RSUs, PSUs, and restrictedstock awards issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Companyrecords expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance,which is based on the estimated fair value of these awards determined at the time of grant, and included within general andadministrative expense and exploration expense in the accompanying statements of operations.Income TaxesThe Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the taxeffects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, asmeasured using current enacted tax rates. These differences will result in taxable income or deductions in future years when thereported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets andassociated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Companyanalysis.99Earnings per ShareBasic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by thebasic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact ofany repurchases of shares of common stock made by the Company.Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for thiscalculation consist of unvested RSUs, contingent PSUs, and in-the-money outstanding stock options. When there is a loss fromcontinuing operations, as was the case for the year ended December 31, 2015, all potentially dilutive shares are anti-dilutive and areconsequently excluded from the calculation of diluted earnings per share.PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, anumber of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the awarddate. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at theend of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. Foradditional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under theEquity Plan.The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, and in-the-money stockoptions. All remaining stock options were exercised during the year ended December 31, 2014.The following table details the weighted-average dilutive and anti-dilutive securities related to RSUs, PSUs, and stock optionsfor the years presented: For the Years Ended December 31, 2015 2014 2013 (in thousands)Dilutive— 814 1,383Anti-dilutive256 — —The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts)Net income (loss)$(447,710) $666,051 $170,935Basic weighted-average common shares outstanding67,723 67,230 66,615Add: dilutive effect of stock options, unvested RSUs, and contingentPSUs (1)— 814 1,383Diluted weighted-average common shares outstanding67,723 68,044 67,998Basic net income (loss) per common share$(6.61) $9.91 $2.57Diluted net income (loss) per common share$(6.61) $9.79 $2.51____________________________________________(1)For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.Comprehensive Income (Loss)Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Othercomprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are100reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net ofincome taxes in the accompanying consolidated statements of comprehensive income (loss).The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Derivative Adjustments(1) Pension LiabilityAdjustments (in thousands)For the year ended December 31, 2013 Net actuarial gain $2,766Reclassification to earnings$1,777 1,239Tax expense(662) (1,522)Income, net of tax$1,115 $2,483For the year ended December 31, 2014 Net actuarial loss $(10,062)Reclassification to earnings$— 706Tax benefit— 3,460Loss, net of tax$— $(5,896)For the year ended December 31, 2015 Net actuarial loss $(4,990)Reclassification to earnings$— 1,853Tax benefit— 1,047Loss, net of tax$— $(2,090)____________________________________________(1)As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had beenreclassified into earnings from AOCL.Fair Value of Financial InstrumentsThe Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable arecarried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’scredit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had$202.0 million of outstanding loans under its credit facility as of December 31, 2015. The Company had $166.0 million of outstandingloans under its credit facility as of December 31, 2014. The Company’s Senior Notes are recorded at cost, net of unamortized deferredfinancing costs, and the respective fair values are disclosed in Note 11 - Fair Value Measurements. The Company has derivativefinancial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimatesprovided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.Industry Segment and Geographic InformationThe Company operates in the exploration and production segment of the oil and gas industry within the United States. TheCompany reports as a single industry segment. The Company sold its Mid-Continent assets in 2015, and therefore, no longer hasmarketed gas volumes as of December 31, 2015. Prior to the sale of these assets, the Company’s gas marketing function providedmostly internal services and acted as the first purchaser of natural gas and natural gas liquids produced by the Company in certaincases. The Company considered its marketing function as ancillary to its oil and gas producing activities. The amount of income theseoperations generated from marketing gas produced by third parties was not material to the Company’s results of operations, andsegmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross101revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenueand marketed gas system expense line items in the accompanying statements of operations.Off-Balance Sheet ArrangementsThe Company has not participated in transactions that generate relationships with unconsolidated entities or financialpartnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have beenestablished for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy isthe primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. The Company has not been involved inany unconsolidated SPE transactions in 2015 or 2014.Recently Issued Accounting StandardsIn May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenuefrom contracts with customers. This guidance is to be applied using a full retrospective method or a modifiedretrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognitionstandard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annualperiods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within thoseannual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessingits impact on the Company’s financial statements and disclosures.In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditionsor events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that theentity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, andto provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016,and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating theprovisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it willimpact the Company’s financial statements or disclosures.Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”)Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifiesincome statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financialstatements or disclosures from the adoption of this standard.In February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidancein GAAP. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in theguidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015.Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on theCompany’s financial statements and disclosures. Effective November 1, 2015, the Company early adopted, on a retrospective basis, FASB ASU No. 2015-03, “Simplifying thePresentation of Debt Issuance Costs” (“ASU 2015-03”). ASU 2015-03 requires deferred financing costs to be presented on theaccompanying balance sheets as a direct deduction from the carrying value of the related debt liability. In accordance, the Companyhas reclassified $33.6 million of deferred financing costs related to its Senior Notes at December 31, 2014, from the other noncurrentassets line item to the Senior Notes, net102of unamortized deferred financing costs line item. The December 31, 2014, accompanying balance sheet line items that were adjustedas a result of the adoption of ASU 2015-03 are presented in the following table: As of December 31, 2014 As Reported As Adjusted (in thousands)Other noncurrent assets$78,214 $44,659Total other noncurrent assets$267,754 $234,199Total Assets$6,516,700 $6,483,145Senior Notes$2,200,000 N/ASenior Notes, net of unamortized deferred financing costsN/A $2,166,445Total noncurrent liabilities$3,445,385 $3,411,830Total Liabilities and Stockholders’ Equity$6,516,700 $6,483,145ASU 2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. InAugust 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated withLine-of-Credit Arrangements” (“ASU 2015-15”) allowing for deferred financing costs associated with line-of-credit arrangements tocontinue to be presented as assets. ASU 2015-15 is consistent with how the Company currently accounts for deferred financing costsrelated to the Company’s revolving credit facility.Effective December 1, 2015, the Company early adopted, on a prospective basis, FASB ASU No. 2015-17, “Balance SheetClassification of Deferred Taxes” (“ASU 2015-17”). ASU 2015-17 requires that deferred tax liabilities and assets, along with anyrelated valuation allowance, be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities andassets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in ASU2015-17. As ASU 2015-17 was adopted on a prospective basis, the Company did not retrospectively adjust prior periods.There are no other accounting standards applicable to the Company that would have a material effect on the Company’sfinancial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2015, and throughthe filing date of this report.103Note 2 – Accounts Receivable and Accounts Payable and Accrued ExpensesAccounts receivable are comprised of the following: As of December 31, 20152014 (in thousands)Accrued oil, gas, and NGL production revenue$58,256 $180,250Amounts due from joint interest owners22,269 58,347Accrued derivative settlements34,579 39,811State severance tax refunds12,072 24,394Other6,948 19,828Total accounts receivable$134,124 $322,630Accounts payable and accrued expenses are comprised of the following: As of December 31, 2015 2014 (in thousands)Accrued capital expenditures$97,355 $357,156Revenue and severance tax payable44,387 63,779Accrued lease operating expense21,943 34,822Accrued property taxes14,078 15,059Accrued compensation41,154 56,279Accrued interest34,378 40,786Other49,222 72,803Total accounts payable and accrued expenses$302,517 $640,684Note 3 – Divestitures, Assets Held for Sale, and Acquisitions2015 Divestiture Activity•Mid-Continent Divestiture. During the second quarter of 2015, the Company divested its Mid-Continent assets in multipletransactions for total divestiture proceeds of $316.8 million and a final net gain of $108.4 million. Certain of these assets werewritten down by $30.0 million to reflect fair value less estimated costs to sell upon reclassification to assets held for sale as ofMarch 31, 2015. This write-down is reflected in the final net gain of $108.4 million discussed above.In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. For the yearended December 31, 2015, the Company recorded $9.3 million of exit and disposal costs, the majority of which were recordedas general and administrative expense in the accompanying statements of operations. Additionally, during the third quarter of2015, the Company vacated its office space in Tulsa. The Company has subleased the space for a portion of the remaining term.As of December 31, 2015, the Company is obligated to pay lease costs of approximately $4.0 million, net of expected incomefrom office space currently subleased, which will be expensed over the duration of the lease, which expires in 2022. Thisobligation will decrease if the Company successfully subleases space for additional terms.•Permian Divestiture. During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region.Total divestiture proceeds were $25.1 million and the estimated total net gain on this divestiture was $2.4 million. Thisdivestiture is subject to normal post-closing adjustments, which are expected to occur in the first half of 2016.104Write-downs on certain other assets held for sale and subsequently sold during the year ended December 31, 2015, totaled$68.6 million. Write-downs on assets held for sale are reflected as a loss on divestiture activity which is included in the net gain ondivestiture activity line item in the accompanying statements of operations. Please refer to Assets Held for Sale below for furtherdiscussion.2014 Divestiture Activity•Rocky Mountain Divestiture. During the second quarter of 2014, the Company divested certain non-core assets in the Montanaportion of the Williston Basin. Total divestiture proceeds were $50.1 million and the final net gain on this divestiture was $26.9million.The Company recorded $27.6 million of write-downs to fair value less estimated costs to sell for assets that were held for saleduring the year ended December 31, 2014, which offset the net gain on the Rocky Mountain divestiture discussed above.2013 Divestiture Activity•Mid-Continent Divestitures. In December 2013, the Company divested of certain non-strategic assets located in its Mid-Continent region, with the largest transaction being the sale of the Company’s Anadarko Basin assets. Total divestiture proceedswere $368.5 million and the final net gain on these divestitures was $25.3 million. A portion of one transaction was structuredto qualify as a like-kind exchange under Section 1031 of the IRC.•Rocky Mountain Divestitures. During 2013, the Company divested of certain non-strategic assets located in its Rocky Mountainregion. Final divestiture proceeds for these divestitures were $57.1 million and the final net gain was $13.2 million. •Permian Divestiture. In December 2013, the Company divested of certain non-strategic assets located in its Permian region.Final divestiture proceeds were $14.0 million and the final net loss was $7.0 million.The Company recorded an immaterial write-down to fair value less estimated costs to sell for assets that were held for sale as ofDecember 31, 2013.Assets Held for SaleAssets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty thesale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and ameasurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Anysubsequent decreases to the estimated fair value less costs to sell impact the measurement of assets held for sale.As of December 31, 2015, the accompanying balance sheets present $641,000 of assets held for sale. There is a correspondingasset retirement obligation liability of $241,000 for assets held for sale included in the asset retirement obligation financial statementline item. Certain assets classified as held for sale and subsequently sold during 2015 were written down to fair value less estimatedcosts to sell, as discussed above.The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accountingunder financial statement presentation authoritative guidance.1052015 Acquisition ActivityThere was no significant acquisition activity during the year ended December 31, 2015.2014 Acquisition Activity•Gooseneck Property AcquisitionsOn September 24, 2014, the Company acquired approximately 61,000 net acres of proved and unproved oil and gas propertiesin its Gooseneck area in North Dakota, along with related equipment, contracts, records, and other assets. Total cashconsideration paid by the Company after final closing adjustments was $321.8 million and the effective date for the acquisitionwas July 1, 2014.On October 15, 2014, the Company acquired additional interests in proved and unproved oil and gas properties in itsGooseneck area. Total cash consideration paid by the Company was $84.8 million and the effective date for the acquisition wasAugust 1, 2014.The Company determined that both of these acquisitions met the criteria of a business combination under Accounting StandardsCodification (“ASC”) Topic 805, Business Combinations. The Company allocated the final adjusted purchase price to theacquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Referto Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair valueof acquired properties. Acquisition #1 Acquisition #2 As of September 24,2014 As of October 15,2014Purchase Price(in thousands)Cash consideration$321,807 $84,836 Fair value of assets and liabilities acquired: Proved oil and gas properties$203,467 $54,612Unproved oil and gas properties126,588 29,610Total fair value of oil and gas propertiesacquired330,055 84,222 Working capital(6,135) 2,232Asset retirement obligation(2,113) (1,618)Total fair value of net assets acquired$321,807 $84,836•Rocky Mountain Acquisitions. In addition to the Gooseneck property acquisitions discussed above, the Company acquired otherproved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multipletransactions for approximately $135.5 million in total cash consideration after final closing adjustments, plusapproximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region.106Note 4 – Income TaxesThe provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands)Current portion of income tax expense Federal $— $— $—State 1,571 868 2,121Deferred portion of income tax expense (benefit) (276,722) 397,780 105,555Total income tax expense (benefit) $(275,151) $398,648 $107,676Effective tax rate 38.1% 37.4% 38.6%The components of the net deferred income tax liabilities are as follows: As of December 31, 2015 2014 (in thousands)Deferred tax liabilities: Oil and gas properties $854,029 $1,029,424Derivative asset 179,543 220,437Other 1,233 4,475Total deferred tax liabilities 1,034,805 1,254,336Deferred tax assets: Federal and state tax net operating loss carryovers 244,942 184,447Stock compensation 14,529 16,763Other liabilities 27,449 25,715Total deferred tax assets 286,920 226,925Valuation allowance (10,394) (7,246)Net deferred tax assets 276,526 219,679Total net deferred tax liabilities (1) $758,279 $1,034,657Current federal income tax refundable $5,378 $4,734Current state income tax refundable $65 $—Current state income tax payable $— $25____________________________________________(1)All deferred tax liabilities and assets as of December 31, 2015, are classified as noncurrent on the accompanying balance sheets upon the Company’sadoption of ASU 2015-17 on a prospective basis. Prior year amounts have not been restated. Please refer to the caption Recently Issued AccountingStandards in Note 1 - Summary of Significant Accounting Policies for additional discussion.At December 31, 2015, the Company estimated its federal net operating loss carryforward at $796.7 million, which includesunrecognized excess income tax benefits associated with stock awards of $126.7 million. The federal net operating loss carryforwardbegins to expire in 2031. The Company has estimated state net operating loss carryforwards of $338.9 million that expire between 2016and 2036 and it has federal R&D credit carryforwards of $7.2 million that expire between 2028 and 2033. The Company’s valuationallowance relates to charitable contribution carryforwards, state net operating loss carryforwards, and state tax credits, which theCompany anticipates will expire before they can be utilized. The change in the valuation allowance from 2014 to 2015 primarilyreflects an allocable change to the Company’s mix of state apportioned losses and the anticipated utilization of state cumulative netoperating losses.107Federal income tax expense differs from the amount that would be provided by applying the statutory United States federalincome tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&Dcredits, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Federal statutory tax expense (benefit)$(253,001) $372,644 $97,514Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit)(21,583) 21,350 9,400Change in valuation allowance3,148 2,245 (314)Research and development credit(1,971) — —Other(1,744) 2,409 1,076Income tax expense (benefit)$(275,151) $398,648 $107,676Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affectapportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, theCompany’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impactsthe total state income tax expense (benefit) reported in the current year. Items affecting state apportionment factors are evaluated at thebeginning of each year, after completion of the prior year income tax return, and when significant acquisition, divestiture, or changes indrilling activity or estimated state revenue occurs during the year.The Company and its subsidiaries file federal income tax returns and various state income tax returns. With certain exceptions,the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before2007. During the first quarter of 2015, as a result of its R&D credit settlement with the IRS Appeals Office in late 2014, the Companyrecorded an additional $2.0 million net R&D credit from a claim filed on an amended return. At December 31, 2015, the Company’s2007 - 2011 IRS examination was still ongoing, but a final agreement was reached in January 2016. There are no material adjustmentsto previously recorded amounts. During the quarter ended September 30, 2015, the IRS initiated an audit of the SM-Mitsui TaxPartnership for the 2013 tax year. The Company has a significant investment in the underlying assets of the tax partnership and thisaudit was still in progress at December 31, 2015.The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount ofunrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in theaccompanying statements of operations includes a negligible amount associated with income taxes. At December 31, 2015, theCompany estimates the range of reasonably possible change in 2016 to the recorded unrecognized tax benefits presented in the tablebelow could be from zero to $1.8 million.The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2015 2014 2013 (in thousands)Beginning balance$1,582 $2,358 $2,278Additions for tax positions of prior years1,200 140 80Settlements— (916) —Ending balance$2,782 $1,582 $2,358108Note 5 – Long-Term DebtRevolving Credit FacilityThe Company’s Fifth Amended and Restated Credit Agreement, as amended, provides a maximum loan amount of $2.5 billion,current aggregate lender commitments of $1.5 billion, and a maturity date of December 10, 2019. The borrowing base is subject toregular semi-annual redeterminations. Effective as of October 7, 2015, the Company’s lenders decreased the borrowing base to $2.0billion as part of the regularly scheduled semi-annual redetermination under the Credit Agreement. This expected reduction from $2.4billion was primarily a result of the Company’s sale of its Mid-Continent assets, plus adjustments consistent with lower commodityprices. There was no change in the current aggregate lender commitments of $1.5 billion. The next redetermination date is scheduledfor April 1, 2016. The borrowing base redetermination process under the credit facility considers the value of the Company’s proved oiland gas properties and commodity derivative contracts, as determined by the lender group. Borrowings under the facility are secured bymortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gas properties. The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement,including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to adjustedEBITDAX, as defined by the Credit Agreement as the ratio of debt to 12-month trailing adjusted EBITDAX, of less than 4.0 and anadjusted current ratio, as defined by the Credit Agreement, of no less than 1.0. The Company was in compliance with all financial andnon-financial covenants under the Credit Agreement as of December 31, 2015, and through the filing date of this report. Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interestat the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) andswingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued onthe unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements ofoperations.Borrowing Base Utilization GridBorrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90%Eurodollar Loans 1.250% 1.500% 1.750% 2.000% 2.250%ABR Loans or Swingline Loans 0.250% 0.500% 0.750% 1.000% 1.250%Commitment Fee Rate 0.300% 0.300% 0.350% 0.375% 0.375%The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity underthe Credit Agreement as of February 17, 2016, December 31, 2015, and December 31, 2014: As of February 17, 2016 As of December 31, 2015 As of December 31, 2014 (in thousands)Credit facility balance (1)$243,000 $202,000 $166,000Letters of credit (2)$200 $200 $808Available borrowing capacity$1,256,800 $1,297,800 $1,333,192____________________________________________(1)Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheetsand thus are not deducted from the credit facility balance.(2)Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.109Senior NotesThe Senior Notes, net of unamortized deferred financing costs, line on the accompanying balance sheets as of December 31,2015, and 2014, consisted of the following: As of December 31, 2015 2014 (1) Senior Notes UnamortizedDeferredFinancing Costs Senior Notes, Netof UnamortizedDeferredFinancing Costs Senior Notes UnamortizedDeferredFinancing Costs Senior Notes, Netof UnamortizedDeferredFinancing Costs (in thousands)6.625% Notes due 2019$— $— $— $350,000 $4,591 $345,4096.50% Notes due 2021350,000 4,106 345,894 350,000 4,806 345,1946.125% Notes due 2022600,000 8,714 591,286 600,000 9,812 590,1886.50% Notes due 2023400,000 5,231 394,769 400,000 5,969 394,0315.0% Notes due 2024500,000 7,455 492,545 500,000 8,377 491,6235.625% Notes due 2025500,000 8,524 491,476 — — —Total$2,350,000 $34,030 $2,315,970 $2,200,000 $33,555 $2,166,445____________________________________________(1)Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the sectionRecently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion.The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing andany future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantorsof the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit theCompany’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however,the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was incompliance with all covenants under its Senior Notes as of December 31, 2015, and through the filing date of this report. All SeniorNotes are registered under the Securities Act as of December 31, 2015. The Company may redeem some or all of its Senior Notes priorto their maturity at redemption prices based on a make-whole amount plus accrued and unpaid interest as described in the indenturesgoverning the notes.2019 NotesOn May 7, 2015, the Company commenced a cash tender offer for any and all of its outstanding 6.625% Senior Notes due 2019at a price of $1,036.88 per $1,000 of principal amount for all 2019 Notes tendered by May 20, 2015 (“Consent Payment Deadline”),and at a price of $1,006.88 per $1,000 of principal amount for all 2019 Notes properly tendered thereafter. On the Consent PaymentDeadline, the Company received tenders and consents from the holders of approximately $242.9 million in aggregate principal amount,or approximately 69 percent, of its outstanding 2019 Notes in connection with the cash tender offer. Following its entry into thesupplemental indenture dated as of May 21, 2015, to the indenture dated as of February 7, 2011, between the Company and U.S. BankNational Association, as Trustee, the Company accepted the 2019 Notes tendered as of the Consent Payment Deadline in exchange forpayment of total consideration, including accrued interest, of approximately $256.2 million under the Tender Offer and ConsentSolicitation. On June 5, 2015, the Company accepted $1.5 million of 2019 Notes tendered after the Consent Payment Deadline inexchange for payment of total consideration, including accrued interest, of approximately $1.6 million.110On June 22, 2015, the Company redeemed the remaining outstanding 2019 Notes at a redemption price of 103.313% of theprincipal amount for payment of total consideration, including accrued interest, of approximately $111.5 million.The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 2019 Notes ofapproximately $16.6 million for the quarter ended June 30, 2015. This amount includes approximately $12.5 million associated withthe premium paid for the tender offer and redemption of the 2019 Notes and approximately $4.1 million related to the acceleration ofunamortized deferred financing costs.2021 NotesOn November 8, 2011, the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021.The 2021 Notes were issued at par and mature on November 15, 2021. The Company received net proceeds of $343.1 million afterdeducting fees of $6.9 million, which are being amortized as deferred financing costs over the life of the 2021 Notes.2022 NotesOn November 17, 2014, the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022.The 2022 Notes were issued at par and mature on November 15, 2022. The Company received net proceeds of $590.0 million afterdeducting fees of $10.0 million, which are being amortized as deferred financing costs over the life of the 2022 Notes.On November 17, 2014, the Company entered into a registration rights agreement that provided holders of the 2022 Notescertain registration rights under the Securities Act. The Company closed its offer to exchange its 2022 Notes for notes registered underthe Securities Act on July 10, 2015.2023 NotesOn June 29, 2012, the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023. The2023 Notes were issued at par and mature on January 1, 2023. The Company received net proceeds of $392.1 million after deductingfees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2023 Notes.2024 NotesOn May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024. The 2024Notes were issued at par and mature on January 15, 2024. The Company received net proceeds of $490.2 million after deducting feesof $9.8 million, which are being amortized as deferred financing costs over the life of the 2024 Notes.2025 NotesOn May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025. The2025 Notes were issued at par and mature on June 1, 2025. The Company received net proceeds of $491.0 million after deducting feesof $9.0 million, which are being amortized as deferred financing costs over the life of the 2025 Notes. The net proceeds were used tofund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining untendered 2019 Notes, as well asrepay outstanding borrowings under the Credit Agreement and for general corporate purposes.111Capitalized InterestCapitalized interest costs for the Company for the years ended December 31, 2015, 2014, and 2013, were $25.1 million, $16.2million, and $11.0 million, respectively.Note 6 – Commitments and ContingenciesCommitmentsThe Company has entered into various agreements, which include drilling rig contracts of $35.3 million, gathering, processing,and transportation throughput commitments of $864.0 million, office leases, including maintenance, of $59.4 million, and othermiscellaneous contracts and leases of $5.7 million. The annual minimum payments for the next five years and total minimum paymentsthereafter are presented below:Years Ending December 31, Amount (1)(in thousands)2016 $132,7472017 128,0742018 131,4892019 142,1612020 141,854Thereafter 288,113Total $964,438____________________________________________(1)During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office,net of sublease income. The Company expects to receive $3.5 million of sublease income as follows: $831,000 in 2016, $953,000 in 2017, $978,000 in2018, and $741,000 in 2019.Drilling rig contractsThe Company has multiple long-term drilling rig contracts. Early termination of these rig contracts as of December 31, 2015,would result in termination penalties of $26.0 million, which would be in lieu of paying the remaining drilling commitments of $35.3million included in the table above. In light of the low commodity price environment, the Company curtailed drilling activity during2015. For the year ended December 31, 2015, the Company incurred $13.7 million of expense related to the early termination ofdrilling rig contracts or fees incurred on rigs placed on standby, which are recorded in the other operating expenses line item in theaccompanying statements of operations. These fees include the costs to terminate the contract for an operated drilling rig in theCompany’s South Texas & Gulf Coast region, in early 2016.Subsequent to December 31, 2015, the Company renegotiated the terms of certain drilling rig contracts to provide increasedflexibility with regard to the timing of activity and payment.Transportation commitments The Company has gathering, processing, and transportation throughput commitments with various third parties that requiredelivery of a minimum amount of 2,277 Bcf of natural gas and 36 MMBbl of crude oil, of which the first 1,059 Bcf of natural gasdelivered under a certain agreement does not have a deficiency payment. These contracts expire at various dates through 2028. TheCompany will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitmentsunder certain agreements. As of December 31, 2015, if the Company delivers no product, the aggregate undiscounted deficiencypayments total approximately $864.0 million. If a shortfall in the minimum volume commitment for natural gas is projected, the112Company has rights under certain contracts to arrange for third party gas to be delivered, and such volumes would count toward itsminimum volume commitment.Subsequent to December 31, 2015, the Company entered into amendments to certain oil gathering and gas gatheringagreements related to certain of its Eagle Ford shale assets, neither of which previously had a minimum volume commitment, in order toobtain more favorable rates and terms. Under these amendments, the Company is now committed to deliver 310 Bcf of natural gas and41 MMBbl of oil through 2034. In the event that the Company delivers no product, the aggregate undiscounted deficiency paymentsunder these amended agreements would be approximately $360.8 million. Subsequent to December 31, 2015, the Company alsoentered into an amendment to a gas gathering agreement related to certain of its other Eagle Ford shale assets, which reduced theCompany’s volume commitment amount as of December 31, 2015, by 829 Bcf and reduced the aggregate undiscounted deficiencypayments by $118.2 million.As of the filing date of this report, the Company does not expect to incur any material shortfalls.Office leasesThe Company leases office space under various operating leases with terms extending as far as 2026. Rent expense, net ofsublease income, for the years ended December 31, 2015, 2014, and 2013, was $6.1 million, $6.5 million, and $5.7 million,respectively. The Company also leases office equipment under various operating leases.ContingenciesThe Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such itemswhen a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of suchpending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of theCompany.The Company is subject to routine severance, royalty and joint interest audits from regulatory authorities, non-operators andothers, as the case may be, and records accruals for estimated exposure when a claim is deemed probable and estimable. Additionally,the Company is subject to various possible contingencies that arise from third party interpretations of the Company’s contracts orotherwise affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil andnatural gas sales may be made, the prices that royalty owners are paid for production from their leases, allowable costs under jointinterest arrangements, and other matters. At December 31, 2015, the Company had $5.3 million accrued for estimated exposure relatedto claims for payment of royalties on certain Federal and Indian leases. Although the Company believes that it has properly estimated itsexposure with respect to the various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustmentscould be required as new interpretations and regulations arise.Note 7 – Compensation PlansEquity PlanThere are several components to the Company’s Equity Plan that are described in this section. Various types of equity awardshave been granted by the Company in different periods.As of December 31, 2015, 2.8 million shares of common stock remained available for grant under the Equity Plan. The issuanceof a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one shareagainst the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares againstthe number of shares available to be granted under the Equity Plan based on the final performance multiplier. Stock options were issuedout of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive StockOption113Plan, both predecessors to the Equity Plan, although the last grant was in 2004, and all remaining stock options were exercised duringthe year ended December 31, 2014.Performance Share Units Under the Equity PlanThe Company grants PSUs to eligible employees as a part of its long-term equity compensation program. The number of sharesof the Company’s common stock issued to settle PSUs ranges from 0% to 200% of the number of PSUs awarded and is determinedbased on certain performance criteria over a three-year measurement period. The performance criteria for the PSUs are based on acombination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performanceof the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensationexpense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respectiveawards.The fair value of PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian MotionModel (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Theseoutcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtainedfor those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stockprices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multipleprospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path thestock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochasticmethod, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significantassumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S.Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields foreach of the Company’s peers.The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as ofthe date of grant. Total compensation expense recorded for PSUs was $10.6 million, $16.0 million, and $16.8 million for the yearsended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, there was $18.4 million of total unrecognizedexpense related to PSUs, which is being amortized through 2018.114A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-AverageGrant-DateFair ValueNon-vested at beginning ofyear (1)433,660 $73.63 572,469 $66.07 669,308 $63.91Granted (1)320,753 $45.34 202,404 $94.66 274,831 $64.13Vested (1)(76,438) $51.76 (206,830) $64.79 (345,005) $60.06Forfeited (1)(51,647) $73.62 (134,383) $86.72 (26,665) $69.74Non-vested at end of year(1)626,328 $61.81 433,660 $73.63 572,469 $66.07____________________________________________(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-yearperformance multiplier, which ranges from zero to two.The fair value of the PSUs granted in 2015, 2014, and 2013 was $14.5 million, $19.2 million, and $17.6 million, respectively.The PSUs granted in 2015, 2014, and 2013 will remain unvested until the third anniversary date of their issuance, at which time theywill fully vest, unless the employee is retirement eligible in which case the PSUs vest immediately upon attainment of retirement age.The total fair value of PSUs that vested during the years ended December 31, 2015, 2014, and 2013 was $4.0 million, $13.4million, and $20.7 million, respectively.During the years ended December 31, 2015, 2014, and 2013, the Company issued 188,279, 85,121, and 387,461 net shares,respectively, of common stock for PSUs granted in 2012, 2011, and 2010 that earned a 1.0, 0.55, and 1.725 multiplier, respectively.The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income andpayroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. As a result, the Companywithheld 100,683, 45,042, and 200,050 shares, respectively, to satisfy income and payroll tax withholding obligations that arose uponthe delivery of the shares underlying the PSUs in 2015, 2014, and 2013, respectively.Restricted Stock Units Under the Equity PlanThe Company grants RSUs to eligible employees as part of its long-term equity incentive compensation program. Restrictionsand vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in theaward agreements. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award atthe end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense andexploration expense over the vesting periods of the award.Total compensation expense recorded for RSUs for the years ended December 31, 2015, 2014, and 2013, was $13.4 million,$13.9 million, and $13.1 million, respectively. As of December 31, 2015, there was $19.3 million of total unrecognized expense relatedto unvested RSU awards, which is being amortized through 2018. The Company records compensation expense associated with theissuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price ofthe Company’s common stock on the day of the grant.115A summary of the status and activity of non-vested RSUs is presented below: For the Years Ended December 31, 2015 2014 2013 RSUs Weighted-AverageGrant-DateFair Value RSUs Weighted-AverageGrant-DateFair Value RSUs Weighted-AverageGrant-DateFair ValueNon-vested at beginning ofyear515,724 $68.29 580,431 $57.05 496,244 $51.81Granted356,246 $43.72 234,560 $83.98 329,939 $60.01Vested(278,289) $63.12 (253,031) $58.19 (207,376) $49.73Forfeited(49,944) $66.53 (46,236) $62.06 (38,376) $54.37Non-vested at end of year543,737 $55.01 515,724 $68.29 580,431 $57.05The fair value of RSUs granted in 2015, 2014, and 2013 was $15.6 million, $19.7 million, and $19.8 million, respectively. TheRSUs granted in 2015, 2014, and 2013 vest one-third of the total grant on each of the next three anniversaries of the date of the grant.The total fair value of RSUs that vested during the years ended December 31, 2015, 2014, and 2013, was $17.6 million, $14.7million, and $10.3 million, respectively.During the years ended December 31, 2015, 2014, and 2013, the Company settled 278,289, 253,031, and 207,378 RSUs,respectively. The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to coverincome and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. As a result, theCompany issued net shares of common stock of 187,244, 171,597, and 139,391 for 2015, 2014, and 2013, respectively. The remaining91,045, 81,434, and 67,987 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery ofthe shares underlying the RSUs for 2015, 2014, and 2013, respectively.Stock Option Grants Under the Equity PlanThe Company previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St.Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004.Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Boardof Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price ofthe Company’s underlying common stock on the grant dates. All stock options granted under the option plans were exercisable for aperiod of up to 10 years from the date of grant. The remaining options from the 2004 grant were exercised during the year endedDecember 31, 2014. As of December 31, 2015, and 2014, there was no unrecognized compensation expense related to stock optionawards.116A summary of activity associated with the Company’s Stock Option Plans during the years ended December 31, 2014, and2013, is presented in the following table: Weighted - Average Aggregate Exercise Intrinsic Shares Price ValueFor the year ended December 31, 2013 Outstanding, start of year267,846 $14.95 Exercised(228,758) $13.92 $12,326,994Forfeited— $— Outstanding, end of year39,088 $20.87 $2,432,837Vested and exercisable at end of year39,088 $20.87 $2,432,837For the year ended December 31, 2014 Outstanding, start of year39,088 $20.87 Exercised(39,088) $20.87 $1,993,726Forfeited— $— Outstanding, end of year— $— $—Vested and exercisable at end of year— $— $—The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Cashreceived from stock options exercised for the years ended December 31, 2014, and 2013, was $4.0 million and $3.2 million,respectively.Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefitsare realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax assetattributable to stock compensation costs for such equity awards. The Company recorded no excess tax benefits for the years endedDecember 31, 2015, 2014, and 2013.Director SharesIn 2015, 2014, and 2013, the Company issued 37,950, 27,677, and 28,169 shares, respectively, of its common stock to its non-employee directors under the Company’s Equity Plan. Additionally, the Company issued 1,953 shares to the Company’s former ChiefExecutive Officer in 2015 for his service as a director through May 2015, following his retirement as an officer of the Company. TheCompany recorded compensation expense related to these issuances of $1.6 million, $1.6 million, and $1.4 million for the years endedDecember 31, 2015, 2014, and 2013, respectively.All shares of common stock issued to the Company’s non-employee directors are earned over the one-year service periodfollowing the date of grant, unless five years of service has been provided to the Company by the director, in which case that director’sshares vest upon the earlier of the completion of the one year service period or the director retiring from the Board of Directors.117Employee Stock Purchase PlanUnder the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’scommon stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in valuefrom purchases for each calendar year. The purchase price of the stock is 85% of the lower of the fair market value of the stock on thefirst or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualifyunder Section 423 of the IRC. The Company had approximately 0.9 million shares available for issuance under the ESPP as ofDecember 31, 2015. There were 197,214, 83,136, and 77,427 shares issued under the ESPP in 2015, 2014, and 2013, respectively.Total proceeds to the Company for the issuance of these shares were $4.8 million, $4.1 million, and $3.7 million for the years endedDecember 31, 2015, 2014, and 2013, respectively.The fair value of ESPP grants is measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expectedvolatility was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S.Treasury yield curve rates with maturities consistent with a six month vesting period.The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-averageassumptions: For the Years Ended December 31, 2015 2014 2013Risk free interest rate0.1% 0.1% 0.1%Dividend yield0.2% 0.1% 0.2%Volatility factor of the expected marketprice of the Company’s common stock61.2% 33.0% 41.1%Expected life (in years)0.5 0.5 0.5The Company expensed $1.8 million, $1.1 million, and $1.1 million for the years ended December 31, 2015, 2014, and 2013,respectively, based on the estimated fair value of the ESPP grants.401(k) PlanThe Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income SecurityAct of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to thecontribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’sbase salary and performance bonus, and may make additional contributions at its discretion. The Company matches contributions madeby employees hired after December 31, 2014, up to nine percent of the employee’s base salary and performance bonus in lieu ofpension plan benefits. Please refer to Note 8 - Pension Benefits for additional discussion of change to pension benefits. The Company’smatching contributions to the 401(k) Plan were $5.6 million, $6.4 million, and $4.2 million for the years ended December 31, 2015,2014, and 2013, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years.Net Profits PlanUnder the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designatedwithin a specific pool. Key employees recommended by senior management and designated as participants by the CompensationCommittee of the Company’s Board of Directors and employed by the Company on the last day of that year became entitled topayments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated withthat pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed atleast annually. The118portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the lastNet Profits Plan pool established by the Company.Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expenseor exploration expense are detailed in the table below: For the Years Ended December 31, 2015 2014 2013 (in thousands)General and administrative expense$3,239 $8,326 $13,734Exploration expense259 690 1,310Total$3,498 $9,016 $15,044Additionally, the Company made or accrued cash payments under the Net Profits Plan of $3.8 million, $8.3 million, and $10.3million for the years ended December 31, 2015, 2014, and 2013, respectively, as a result of divestitures of properties subject to the NetProfits Plan. These cash payments are accounted for as a reduction in the net gain on divestiture activity line item in the accompanyingstatements of operations.The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate lineitem in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit inthe current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated togeneral and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gasproperties in the respective pools rather than results being realized through current period production. If the Company allocated thechange in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company,such expenses or benefits would predominately be allocated to general and administrative expense. As time has passed, the amountdistributed relating to prospective exploration efforts has become insignificant as more is paid to employees that have terminatedemployment and do not provide ongoing exploration support to the Company.Note 8 – Pension BenefitsThe Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age andservice requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan coveringcertain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”).The Company froze the Pension Plans to new participants, effective as of December 31, 2015. Employees participating in the PensionPlans as of December 31, 2015, will continue to earn benefits.Obligations and Funded Status for the Pension PlansThe Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefitobligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes acorresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarialpresent value of the benefits earned to date by plan participants based on employee service and compensation including the effect ofassumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation butexcludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December31.119 For the Years Ended December 31, 2015 2014 (in thousands)Change in benefit obligation: Projected benefit obligation at beginning of year$57,867 $43,285Service cost7,949 6,335Interest cost2,496 2,191Actuarial loss2,397 8,821Benefits paid(8,162) (2,765)Projected benefit obligation at end of year62,547 57,867 Change in plan assets: Fair value of plan assets at beginning of year27,940 24,658Actual return on plan assets(410) 737Employer contribution6,401 5,310Benefits paid(8,162) (2,765)Fair value of plan assets at end of year25,769 27,940Funded status at end of year$(36,778) $(29,927)The Company’s underfunded status for the Pension Plans as of December 31, 2015, and 2014, is $36.8 million and $29.9million, respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assetsof the Qualified Pension Plan were returned to the Company during the year ended December 31, 2015. There are no plan assets in theNonqualified Pension Plan.Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2015 2014 (in thousands)Projected benefit obligation$62,547 $57,867 Accumulated benefit obligation$46,439 $43,205Less: Fair value of plan assets(25,769) (27,940)Underfunded accumulated benefit obligation$20,670 $15,265Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during aperiod) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on planassets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice isintended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences betweenactual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain orloss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and lossesnot yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of theyear, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-relatedvalue of plan assets, then the amortization is the excess divided by the average remaining service period of participating employeesexpected to receive benefits under the plan.120Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensiveloss as of December 31, 2015 and 2014, consist of: As of December 31, 2015 2014 (in thousands)Unrecognized actuarial losses$20,966 $17,812Unrecognized prior service costs101 118Unrecognized transition obligation— —Accumulated other comprehensive loss$21,067 $17,930The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over thenext fiscal year is $1.5 million.Pre-tax changes recognized in other comprehensive income (loss) during 2015, 2014, and 2013, were as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Net actuarial gain (loss)$(4,990) $(10,062) $2,766Prior service cost— — —Less: Amortization of prior service cost(17) (17) (17)Amortization of net actuarial loss(1,486) (689) (1,222)Settlements(350) — —Total other comprehensive income (loss)$(3,137) $(9,356) $4,005Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2015 2014 2013 (in thousands)Components of net periodic benefit cost: Service cost$7,949 $6,335 $6,291Interest cost2,496 2,191 1,627Expected return on plan assets that reducesperiodic pension cost(2,182) (1,978) (1,538)Amortization of prior service cost17 17 17Amortization of net actuarial loss1,486 689 1,222Settlements350 — —Net periodic benefit cost$10,116 $7,254 $7,619Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets areamortized over the average remaining service period of active participants.121Pension Plan AssumptionsWeighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are asfollows: As of December 31, 2015 2014 2013Projected benefit obligation Discount rate4.7% 4.3% 5.0%Rate of compensation increase6.2% 6.2% 6.2%Net periodic benefit cost Discount rate4.3% 5.0% 3.9%Expected return on plan assets (1)7.5% 7.5% 7.5%Rate of compensation increase6.2% 6.2% 6.2%____________________________________________(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.The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets areprudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit thedirect investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term andaccordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and returnbehavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targetingthe optimal expected returns for given levels of risk are applied.The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying ratesof return. The investments are further diversified within each asset classification. This portfolio diversification provides protectionagainst a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual assetallocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation ofthe Qualified Pension Plan is as follows: Target As of December 31,Asset Category 2016 2015 2014Equity securities 42.0% 39.1% 39.6%Fixed income securities 35.0% 34.0% 33.9%Other securities 23.0% 26.9% 26.5%Total 100.0% 100.0% 100.0%There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return onplan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2015 and 2014. Factorsconsidered in determining the expected rate of return include the long-term historical rate of return provided by the equity and debtsecurities markets and input from the investment consultants and trustees managing the plan assets. The difference in investmentincome using the projected rate of return compared to the actual rates of return for the past two years was not material and is notexpected to have a material effect on the accompanying statements of operations or cash flows from operating activities in future years.122Fair Value AssumptionsThe fair values of the Company’s Qualified Pension Plan assets as of December 31, 2015 and 2014, utilizing the fair valuehierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual AssetAllocation Total Level 1Inputs Level 2Inputs Level 3Inputs (in thousands)As of December 31, 2015 Cash—% $— $— $— $—Equity Securities: Domestic (1)26.1% 6,729 4,943 1,786 —International (2)13.0% 3,353 3,353 — —Total Equity Securities39.1% 10,082 8,296 1,786 —Fixed Income Securities: High-Yield Bonds (3)2.8% 722 722 — —Core Fixed Income (4)22.5% 5,789 5,789 — —Floating Rate Corp Loans (5)8.7% 2,247 2,247 — —Total Fixed Income Securities34.0% 8,758 8,758 — —Other Securities: Commodities (6)2.7% 700 700 — —Real Estate (7)5.8% 1,499 — — 1,499Collective Investment Trusts (8)4.6% 1,184 — 1,184 —Hedge Fund (9)13.8% 3,546 — — 3,546Total Other Securities26.9% 6,929 700 1,184 5,045Total Investments100.0% $25,769 $17,754 $2,970 $5,045 As of December 31, 2014 Cash—% $— $— $— $—Equity Securities: Domestic (1)27.1% 7,569 5,550 2,019 —International (2)12.5% 3,498 3,498 — —Total Equity Securities39.6% 11,067 9,048 2,019 —Fixed Income Securities: High-Yield Bonds (3)2.9% 797 797 — —Core Fixed Income (4)22.4% 6,247 6,247 — —Floating Rate Corp Loans (5)8.6% 2,413 2,413 — —Total Fixed Income Securities33.9% 9,457 9,457 — —Other Securities: Commodities (6)2.9% 810 810 — —Real Estate (7)4.7% 1,327 — — 1,327Collective Investment Trusts (8)4.1% 1,149 — 1,149 —Hedge Fund (9)14.8% 4,130 593 — 3,537Total Other Securities26.5% 7,416 1,403 1,149 4,864Total Investments100.0% $27,940 $19,908 $3,168 $4,864____________________________________________123(1)Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upondemand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlyinginvestments 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 collectiveinvestment funds.(2)International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquidmarkets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financialproductivity 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 theincreased level of default risk, security selection focuses on credit-risk analysis.(4)The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’sCapital 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 levelof 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 estateentails 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 underlyinginvestments 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 offunds that invests both long and short using a variety of investment strategies. Included below is a summary of the changes in Level 3 plan assets (in thousands):Balance at January 1, 2014$3,421Purchases1,232Realized gain on assets144Unrealized gain on assets67Balance at December 31, 2014$4,864Purchases—Realized gain on assets165Unrealized gain on assets16Balance at December 31, 2015$5,045ContributionsThe Company contributed $6.4 million, $5.3 million, and $5.0 million, to the Pension Plans in the years ended December 31,2015, 2014, and 2013, respectively. The Company expects to make a $5.8 million contribution to the Pension Plans in 2016.124Benefit PaymentsThe Pension Plans made actual benefit payments of $8.2 million, $2.8 million, and $3.3 million in the years endedDecember 31, 2015, 2014, and 2013, respectively. Expected benefit payments over the next 10 years are as follows:Years Ending December 31, (in thousands)2016 $3,6182017 $4,3502018 $4,6052019 $6,0572020 $6,8462021 through 2025 $47,188Note 9 – Asset Retirement ObligationsThe Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gasproperties. A liability for the fair value of an asset retirement obligation (“ARO”) and a corresponding increase to the carrying value ofthe related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oiland gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costsand recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of therespective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’saccompanying statements of cash flows.The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoningwells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liabilityis discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-freerates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequentto initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passageof time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors or theCompany’s credit-adjusted risk-free rate as market conditions warrant.A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2015 2014 (in thousands)Beginning asset retirement obligation$122,124 $121,186Liabilities incurred14,471 13,506Liabilities settled(24,781) (11,372)Accretion expense5,091 6,090Revision to estimated cash flows23,969 (7,286)Ending asset retirement obligation$140,874 $122,124As of December 31, 2015 and 2014, accounts payable and accrued expenses contain $3.3 million and $1.3 million,respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costsassociated with platform structures that are being retired, which are also included in the table above.125Note 10 – Derivative Financial InstrumentsSummary of Oil, Gas, and NGL Derivative Contracts in PlaceThe Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentiallyadverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivative contracts consist of swap arrangements for oil, gas, and NGLs.As of December 31, 2015, the Company had commodity derivative contracts outstanding through the second quarter of 2020for a total of 5.6 million Bbls of oil production, 172.7 million MMBtu of gas production, and 13.0 million Bbls of NGL production.In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than theswap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index priceis higher than the swap fixed price, the Company pays the difference. The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place asof December 31, 2015:Oil SwapsContract Period NYMEX WTI Volumes Weighted-AverageContractPrice (Bbls) (per Bbl)First quarter 2016 1,868,000 $86.93Second quarter 2016 1,752,000 $86.73Third quarter 2016 1,170,000 $90.29Fourth quarter 2016 780,000 $90.05All oil swaps 5,570,000 126Natural Gas SwapsContract Period Volumes Weighted-AverageContractPrice (MMBtu) (per MMBtu)First quarter 2016 23,341,000 $3.82Second quarter 2016 20,780,000 $3.40Third quarter 2016 18,829,000 $3.38Fourth quarter 2016 17,236,000 $3.822017 37,528,000 $4.092018 30,606,000 $4.272019 24,415,000 $4.34All gas swaps* 172,735,000 ____________________________________________*Natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (95%), IF NGPL TXOK (1%), and IF NNG Ventura (2%).NGL Swaps OPIS Purity Ethane MontBelvieu OPIS Propane Mont BelvieuNon-TET OPIS Normal Butane MontBelvieu Non-TET OPIS Isobutane MontBelvieu Non-TETContract Period VolumesWeighted-Average ContractPrice VolumesWeighted-AverageContract Price VolumesWeighted-AverageContract Price VolumesWeighted-AverageContract Price (Bbls)(per Bbl) (Bbls)(per Bbl) (Bbls)(per Bbl) (Bbls)(per Bbl)First quarter 2016 926,000$8.29 1,059,000$19.60 143,000$25.62 122,000$25.87Second quarter 2016 828,000$8.28 949,000$19.64 130,000$25.62 111,000$25.87Third quarter 2016 751,000$8.70 862,000$19.03 —$— —$—Fourth quarter 2016 688,000$8.71 791,000$18.53 —$— —$—2017 2,271,000$9.16 —$— —$— —$—2018 1,671,000$10.65 —$— —$— —$—2019 1,200,000$10.92 —$— —$— —$—2020 539,000$11.13 —$— —$— —$—Total NGL swaps 8,874,000 3,661,000 273,000 233,000 127Commodity Derivative Contracts Entered Into After December 31, 2015Subsequent to December 31, 2015, the Company restructured certain of its gas derivative contracts by buying fixed pricevolumes to exactly offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then enteredinto new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or otherconsideration was included as part of the restructuring. The net result of buying fixed price volumes in 2018 and 2019 is that theCompany no longer has protection against natural gas price volatility in those years. These updated contracts are reflected in thefollowing table, which summarizes the approximate gas volumes and average contract prices of contracts the Company had in place asof February 17, 2016, including derivatives contracts for settlement anytime during the first quarter of 2016 and later periods:Natural Gas SwapsContract Period Volumes Weighted-AverageContractPrice PurchasedVolumes Weighted-AverageContractPrice Total Volumes (MMBtu) (per MMBtu) (MMBtu) (per MMBtu) (MMBtu)First quarter 2016 23,341,000 $3.82 — $— 23,341,000Second quarter 2016 20,780,000 $3.40 — $— 20,780,000Third quarter 2016 18,829,000 $3.38 — $— 18,829,000Fourth quarter 2016 17,236,000 $3.82 — $— 17,236,0002017 76,135,000 $4.26 — $— 76,135,0002018 30,606,000 $4.27 (30,606,000) $4.27 —2019 24,415,000 $4.34 (24,415,000) $4.34 —All gas swaps* 211,342,000 (55,021,000) 156,321,000____________________________________________*Total volumes of natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (96%), IF NGPL TXOK (1%), and IF NNGVentura (1%).Additionally, subsequent to December 31, 2015, the Company entered into NGL fixed price swap contracts for 1.6 million Bblsof ethane production through 2018 with an average contract price of $8.67 per Bbl and 235,000 Bbls of isobutane production throughthe fourth quarter of 2016 with a contract price of $22.58 per Bbl.Derivative Assets and Liabilities Fair ValueThe Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets asderivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $488.4 million and $592.1million at December 31, 2015 and 2014, respectively.The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands)Commodity ContractsCurrent assets $367,710 Current liabilities $8Commodity ContractsNoncurrent assets 120,701 Noncurrent liabilities —Derivatives not designated as hedginginstruments $488,411 $8128 As of December 31, 2014 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands)Commodity ContractsCurrent assets $402,668 Current liabilities $—Commodity ContractsNoncurrent assets 189,540 Noncurrent liabilities 70Derivatives not designated as hedginginstruments $592,208 $70Offsetting of Derivative Assets and LiabilitiesAs of December 31, 2015 and 2014, all derivative instruments held by the Company were subject to master nettingarrangements by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amountspayable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and inthe same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the rightto offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy isto not offset these positions in its accompanying balance sheets.The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balancesheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31,Offsetting of Derivative Assets and Liabilities 2015 2014 2015 2014 (in thousands)Gross amounts presented in the accompanying balance sheets $488,411 $592,208 $(8) $(70)Amounts not offset in the accompanying balance sheets (8) (70) 8 70Net amounts $488,403 $592,138 $— $—Discontinuance of Cash Flow Hedge AccountingAs of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previouslydesignated as cash flow hedges at December 31, 2010. Fair values at December 31, 2010, were frozen in AOCL as of the de-designation date and were reclassified into earnings as the original derivative transactions settled. As of September 30, 2013, allcommodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified intoearnings from AOCL.Subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fairvalues immediately in earnings rather than deferring any such amounts in AOCL. The Company had no derivatives designated as cashflow hedges for the years ended December 31, 2015, 2014, and 2013, and no new gains or losses were deferred to AOCL during theserespective years. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivativeinstruments, including its valuation techniques.129The following table summarizes the components of derivative gain presented in the accompanying statements of operations: For the Years Ended December 31, 2015 2014 2013 (in thousands)Derivative settlement (gain) loss: Oil contracts$(362,219) $(28,410) $15,161Gas contracts (1)(123,180) 26,706 (30,338)NGL contracts(27,167) (10,911) (6,885)Total derivative settlement gain$(512,566) $(12,615) $(22,062) Total derivative (gain) loss: Oil contracts$(191,165) $(457,082) $14,665Gas contracts(189,734) (93,267) (14,053)NGL contracts(27,932) (32,915) (3,692)Total derivative gain$(408,831) $(583,264) $(3,080)____________________________________________(1) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of earlysettlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. The following table details the effect of derivative instruments on AOCL and the accompanying statements of operations (net ofincome tax): Location onAccompanyingStatements ofOperations For the Years Ended December 31, Derivatives 2015 2014 2013 (in thousands)Amount reclassified from AOCLCommodityContracts Other operatingrevenues $— $— $1,115 The realized net hedge loss for the year ended December 31, 2013, shown net of income tax in the table above, is comprised ofrealized settlements on commodity derivative contracts that were previously designated as cash flow hedges. Realized hedge gains orlosses from the settlement of commodity derivatives previously designated as cash flow hedges are reported in the other operatingrevenues line item on the accompanying statements of operations. The Company realized a pre-tax net loss of $1.8 million from itscommodity derivative contracts that were previously designated as cash flow hedges for the year ended December 31, 2013.Credit Related Contingent FeaturesAs of December 31, 2015, and through the filing date of this report, all of the Company’s derivative counterparties weremembers of the Company’s credit facility lender group. The Company’s obligations under its credit facility and derivative contracts aresecured by mortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gasproperties.130Note 11 – Fair Value MeasurementsThe Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. Thisguidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderlytransaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values,followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for groupingthese assets and liabilities is based on the significance level of the following inputs:•Level 1 – quoted prices in active markets for identical assets or liabilities•Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments inmarkets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers areobservable•Level 3 – significant inputs to the valuation model are unobservableThe following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanyingbalance sheets and where they are classified within the fair value hierarchy as of December 31, 2015: Level 1 Level 2 Level 3 (in thousands)Assets: Derivatives (1)$— $488,411 $—Proved oil and gas properties (2)$— $— $124,184Other property and equipment (2)$— $— $629Liabilities: Derivatives (1)$— $8 $—Net Profits Plan (1)$— $— $7,611____________________________________________(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanyingbalance sheets and where they are classified within the fair value hierarchy as of December 31, 2014: Level 1 Level 2 Level 3 (in thousands)Assets: Derivatives (1)$— $592,208 $—Proved oil and gas properties (2)$— $— $33,423Oil and gas properties held for sale (2)$— $— $17,891Liabilities: Derivatives (1)$— $70 $—Net Profits Plan (1)$— $— $27,136____________________________________________(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.131Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowestlevel of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by theCompany as well as the general classification of such instruments pursuant to the above fair value hierarchy.DerivativesThe Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are basedupon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves,counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to therespective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believesprovides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by theCompany are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivativemarkets are highly active.Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality.However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of theinstrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if theirratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty.Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivativeliability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may haveposted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment isconsistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current creditfacility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties aremembers of the Company’s credit facility lender group.The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not bereflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate andconsistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third partiesmay use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in adifferent estimate of fair value at the reporting date.Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.132Net Profits PlanThe Net Profits Plan is a standalone liability for which there is no available market price, principal market, or marketparticipants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Companyemploys the income valuation technique, which converts expected future cash flow amounts to a single present value amount. Thistechnique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, therisk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGLcommodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger NetProfits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability.The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Planbased on the discounted value of estimated future payments associated with each individual pool. Discount rates of 10 percent and 12percent were used to calculate this liability as of December 31, 2015, and 2014, respectively, and are intended to represent theCompany’s best estimate of the present value of expected future payments under the Net Profits Plan.The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overallmarket conditions. The Company regularly assesses the current market environment. The Net Profits Plan liability is determined usingprice assumptions of five one-year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjustedfor realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevantperiods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due tofluctuations that occur in the oil, gas, and NGL commodity markets.If the commodity prices used in the calculation changed by five percent, the liability recorded at December 31, 2015, woulddiffer by approximately $1.1 million. A one percent increase or decrease in the discount rate would result in a change of approximately$300,000. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realizedcommodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cashpayments are inherently different from the amounts estimated.No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such,the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to theCompany’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discountrate and the expected future cash flows, are derived from the Company’s own calculations and estimates. 133The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Years Ended December 31, 2015 2014 2013 (in thousands)Beginning balance$27,136 $56,985 $78,827Net increase (decrease) in liability (1)(12,238) (12,492) 3,527Net settlements (1) (2)(7,287) (17,357) (25,369)Transfers in (out) of Level 3— — —Ending balance$7,611 $27,136 $56,985____________________________________________(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 ofoperations.(2)Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued underthe Net Profits Plan of $3.8 million, $8.3 million, and $10.3 million for the years ended December 31, 2015, 2014, and 2013, respectively, as a result ofthe divestitures of properties subject to the Net Profits Plan.Long-Term DebtThe following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary markettrading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of December 31, 2015 or2014, as they are recorded at carrying value, net of unamortized deferred financing costs. As of December 31, 2015 2014 (in thousands)2019 Notes (1)$— $350,0182021 Notes$262,938 $343,0002022 Notes$440,250 $556,5002023 Notes$296,000 $379,0002024 Notes$334,065 $435,0002025 Notes (1)$326,875 $—____________________________________________(1) The 2019 Notes were fully redeemed on June 22, 2015 and the 2025 Notes were issued on May 21, 2015.The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, basedon prevailing market rates.Proved and Unproved Oil and Gas PropertiesProved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication thecarrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts futureamounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates andprice forecasts representative of the current operating environment, as selected by the Company’s management. The calculation of thediscount rate is based on the best information available and was estimated to be 10 percent to 15 percent based on the reservoir specificweightings of future estimated proved and unproved cash flows as of December 31, 2015. A 12 percent discount rate was134estimated as of December 31, 2014. The Company believes the discount rate is representative of current market conditions and takesinto account estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing ofcash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjustedfor basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLsare forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used.Future operating costs are also adjusted as deemed appropriate for these estimates. The Company recorded impairment of proved oiland gas properties expense of $468.7 million for the year ended December 31, 2015, due to the decline in proved and risk-adjustedprobable and possible reserve expected cash flows, driven by the continued commodity price declines. Impairments were recordedmainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in theRocky Mountain region. These assets were impaired to fair value totaling $124.2 million as of December 31, 2015. The Companyrecorded impairment of proved oil and gas properties expense of $84.5 million for the year ended December 31, 2014, resulting fromthe significant decline in commodity prices at the end of 2014 and recognition of the outcomes of exploration and delineation wells incertain prospects in the Company’s South Texas & Gulf Coast and Permian regions. As of December 31, 2014, proved oil and gasproperties measured at fair value totaled $33.4 million.Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that thecarrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, whichtakes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, andestimated reserve values. The Company recorded abandonment and impairment of unproved oil and gas properties expense of $78.6million and $75.6 million for the years ended December 31, 2015, and 2014, respectively, resulting from lease expirations and acreagethe Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices.Unproved properties measured at fair value were zero in the accompanying balance sheets as of December 31, 2015, and 2014.Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication thecarrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique ormarket approach depending on the quality of information available to support management’s assumptions and the circumstances. Thevaluation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flowsassociated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of otherproperty and equipment expense of $49.4 million for the year ended December 31, 2015, on the Company’s gathering system assets inits east Texas program. These assets were impaired in conjunction with the impairment of the associated proved and unprovedproperties, which the Company does not intend to develop during an environment of sustained low commodity prices. The fair value ofthese assets at December 31, 2015, was $629,000.Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using amarket approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties, ifavailable. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above.Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidencedby the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreagevalue based on the price received for similar acreage in recent transactions by the Company or other market participants in the principalmarket. For the years ended December 31, 2015, and 2014, write-downs on certain assets held for sale totaled $98.6 million and $27.6million, respectively. These write-downs are included within the net gain on divestiture activity line item on the accompanyingstatements of operations. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for further discussion. There wereno assets held for sale recorded at fair value as of December 31, 2015, as the carrying value was below the estimated fair value lesscosts to sell. As of December 31, 2014, assets held for sale measured at fair value totaled $17.9 million.135The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisitiondate using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs.Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) futureoperating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a marketparticipant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’smanagement at the time of the valuation. Refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additionalinformation on the fair value of assets acquired during 2014.Note 12 - Acquisition and Development AgreementIn June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui (the “Acquisition andDevelopment Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle,Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui expended anaggregate $680.0 million on behalf of the Company. The Acquisition and Development Agreement also provided for reimbursement ofcapital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during theperiod between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover theCompany’s remaining 10 percent of drilling and completion costs for the affected acreage.During the second quarter of 2014, the remainder of the carry under the Acquisition and Development Agreement wasexpended. Accordingly, the Company accrued and funded its full share of drilling and completion costs in its non-operated Eagle Fordshale program for the remainder of 2014 and all of 2015.Note 13 - Suspended Well CostsThe following table reflects the net changes in capitalized exploratory well costs during 2015, 2014, and 2013. The table doesnot include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2015 2014 2013 (in thousands)Beginning balance on January 1,$43,589 $34,527 $9,100Additions to capitalized exploratory well costs pending thedetermination of proved reserves11,952 43,589 34,527Divestitures(809) — —Reclassifications to wells, facilities, and equipment based on thedetermination of proved reserves(18,485) (33,340) (9,100)Capitalized exploratory well costs charged to expense(24,295) (1,187) —Ending balance at December 31,$11,952 $43,589 $34,527As of December 31, 2015, there were no exploratory well costs that were capitalized for more than one year.136Supplemental Oil and Gas Information (unaudited)Costs Incurred in Oil and Gas Producing ActivitiesCosts incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, aresummarized as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Development costs (1)$1,234,114 $1,782,324 $1,350,116Exploration costs132,465 288,270 168,612Acquisitions Proved properties10,040 272,902 29,859Unproved properties (2)18,382 368,208 172,546Total, including asset retirement obligation (3)(4)$1,395,001 $2,711,704 $1,721,133____________________________________________(1)Includes facility costs of $75.6 million, $75.1 million, and $49.5 million for the years ended December 31, 2015, 2014, and 2013, respectively.(2)Includes $924,000, $288.7 million, and $58.5 million of unproved properties acquired as part of proved property acquisitions for the years endedDecember 31, 2015, 2014, and 2013, respectively. The remaining balance relates to leasing activity.(3)Includes capitalized interest of $25.1 million, $16.2 million, and $11.0 million for the years ended December 31, 2015, 2014, and 2013, respectively.(4)Includes amounts relating to estimated asset retirement obligations of $38.5 million, $11.4 million, and $26.8 million for the years ended December 31,2015, 2014, and 2013, respectively.Oil and Gas Reserve QuantitiesThe reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gasproducing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and underexisting economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right tooperate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methodsare used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir isto be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the periodcovered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within suchperiod, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of theCompany’s estimated proved reserves are located in the United States.137The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended December 31, 2015. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80percent of the Company’s total calculated proved reserve PV-10 for each year presented. The Company emphasizes that reserveestimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimatesof established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomesavailable. For the Years Ended December 31, 2015 (1) 2014 (2) 2013 (3) Oil Gas NGLs Oil Gas NGLs Oil Gas NGLs (MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl)Total proved reserves: Beginning ofyear169.7 1,466.5 133.5 126.6 1,189.3 103.9 92.2 833.4 62.3Revisions ofpreviousestimate(46.2) (369.6) (40.6) (5.1) 46.0 7.8 (5.2) 68.8 (1.3)Discoveriesandextensions16.9 122.3 9.3 15.0 103.5 10.5 34.6 399.2 39.8Infill reservesin anexistingproved field24.9 356.2 29.7 32.0 270.8 24.1 21.6 118.7 13.2Sales of reserves (4)(1.9) (138.4) (0.4) (1.9) (1.1) — (3.4) (85.1) (0.6)Purchases ofminerals inplace1.1 0.6 — 19.8 10.9 0.2 0.7 3.6 —Production(19.2) (173.6) (16.1) (16.7) (152.9) (13.0) (13.9) (149.3) (9.5)End of year145.3 1,264.0 115.4 169.7 1,466.5 133.5 126.6 1,189.3 103.9 Proved developed reserves: Beginning ofyear89.3 784.6 66.7 70.2 569.2 43.8 58.8 483.2 27.2End of year75.6 644.4 61.5 89.3 784.6 66.7 70.2 569.2 43.8Proved undeveloped reserves: Beginning ofyear80.4682.066.8 56.3 620.1 60.2 33.5 350.2 35.1End of year69.6619.753.9 80.4 682.0 66.8 56.3 620.1 60.2____________________________________________Note: Amounts may not calculate due to rounding.(1)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 theEagle Ford shale and Bakken/Three Forks plays. The Company had net negative engineering revisions of 148.6 MMBOE, consisting of 47.3MMBOE of positive performance revisions in the Eagle Ford shale and Bakken/Three Forks plays resulting from enhanced completions andreductions in operating expenses, offset by a 116.5 MMBOE negative price revision due to the decline in commodity prices in 2015 and theremoval of 79.4 MMBOE of proved undeveloped reserves due to the five-year rule.(2)For the year ended December 31, 2014, the Company added 143.9 MMBOE from its drilling program and had upward engineering revisions of 10.4MMBOE related primarily to improved performance and lower operating expenses in its operated Eagle Ford assets.(3)For the year ended December 31, 2013, the Company added 195.5 MMBOE from its drilling program and had upward engineering revisions of 5.0MMBOE related primarily to an upward performance revision of 4.4 MMBOE.(4)Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information on assets divested.138Standardized Measure of Discounted Future Net Cash FlowsThe Company computes a standardized measure of future net cash flows and changes therein relating to estimated provedreserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs aredetermined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated futurereserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation.Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated futurestatutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discountfactor.Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing theproved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plusCompany overhead incurred by the central administrative office attributable to operating activities.The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptionsdo not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present valueamount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to thestandardized measure computations since these reserve quantity estimates are the basis for the valuation process. The following pricesas adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure: For the Years Ended December 31, 2015 2014 2013Oil (per Bbl)$42.98 $84.65 $90.19Gas (per Mcf)$2.48 $4.63 $3.99NGLs (per Bbl)$16.99 $35.48 $35.92139The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based onthe standardized measure. As of December 31, 2015 2014 2013 (in thousands)Future cash inflows$11,337,865 $25,897,730 $19,895,360Future production costs(6,234,687) (9,986,239) (7,771,747)Future development costs(2,005,599) (3,294,164) (2,891,325)Future income taxes— (3,511,352) (2,722,230)Future net cash flows3,097,579 9,105,975 6,510,05810 percent annual discount(1,228,671) (3,407,192) (2,500,619)Standardized measure of discounted future netcash flows$1,868,908 $5,698,783 $4,009,439The principle sources of changes in the standardized measure of discounted future net cash flows are: For the Years Ended December 31, 2015 2014 2013 (in thousands)Standardized measure, beginning of year$5,698,783 $4,009,439 $3,021,014Sales of oil, gas, and NGLs produced, net of productioncosts(776,272) (1,765,666) (1,602,505)Net changes in prices and production costs(4,709,908) (75,966) 142,199Extensions, discoveries and other including infill reservesin an existing proved field, net of related costs386,069 1,819,657 2,309,075Sales of reserves in place(262,210) (49,736) (259,031)Purchase of reserves in place4,686 413,175 30,771Previously estimated development costs incurred duringthe period449,738 1,015,694 581,107Changes in estimated future development costs191,447 138,247 68,613Revisions of previous quantity estimates(1,819,639) 167,500 82,226Accretion of discount761,746 552,852 384,914Net change in income taxes1,863,868 (399,587) (690,953)Changes in timing and other80,600 (126,826) (57,991)Standardized measure, end of year$1,868,908 $5,698,783 $4,009,439140Quarterly Financial Information (unaudited)The Company’s quarterly financial information for fiscal years 2015 and 2014 is as follows (in thousands, except per shareamounts): First Second (2) Third (3) Fourth (3) (4) Quarter Quarter Quarter QuarterYear Ended December 31, 2015 Total operating revenues and other income$365,934 $516,146 $371,151 $303,734Total operating expenses420,369 567,025 339,047 809,307Income (loss) from operations$(54,435) $(50,879) $32,104 $(505,573)Loss before income taxes$(86,511) $(98,211) $(1,026) $(537,113)Net income (loss)$(53,058) $(57,508) $3,114 $(340,258)Basic net income (loss) per common share(1)$(0.79) $(0.85) $0.05 $(5.01)Diluted net income (loss) per common share(1)$(0.79) $(0.85) $0.05 $(5.01)Dividends declared per common share$0.05 $— $0.05 $— Year Ended December 31, 2014 Total operating revenues and other income$632,720 $674,980 $618,786 $595,821Total operating expenses504,086 553,264 261,807 37,336Income from operations$128,634 $121,716 $356,979 $558,485Income before income taxes$104,470 $95,829 $333,686 $530,714Net income$65,607 $59,780 $208,938 $331,726Basic net income per common share(1)$0.98 $0.89 $3.10 $4.92Diluted net income per common share(1)$0.96 $0.88 $3.05 $4.91Dividends declared per common share$0.05 $— $0.05 $—____________________________________________(1)Amounts may not sum due to rounding.(2)During the second quarter of 2015, the Company recorded a $71.9 million net gain on divestiture activity resulting from the sale of its Mid-Continentassets offset by write-downs on certain other assets held for sale. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions in Part II,Item 8 of this report for additional information. Additionally, the Company recorded a $16.6 million net loss on the early extinguishment of its 2019Notes. Please refer to Note 5 - Long-Term Debt in Part II, Item 8 of this report for additional information.(3)The volatility of commodity prices at the end of 2014 and throughout 2015 has resulted in significant net derivative gains recorded for the years endedDecember 31, 2015, and 2014, with the third quarter of 2015 including a $212.3 million net derivative gain and the third and fourth quarters of 2014including a $190.7 million and $616.7 million net derivative gain, respectively. Please refer to the caption Derivative gain included in Comparison ofFinancial Results and Trends between 2015 and 2014 and between 2014 and 2013 included in Part II, Item 7 of this report for additional discussion.(4)During the fourth quarter of 2015, the Company recorded $344.2 million of impairment of proved properties expense, $54.6 million of abandonment andimpairment of unproved properties expense, and $49.4 million of impairment of other property and equipment expense. During the fourth quarter of2014, the Company recorded $84.5 million of impairment of proved properties expense and $57.2 million of abandonment and impairment of unprovedproperties expense. Please refer to the caption Impairment of Proved and Unproved Properties included in Note 1 - Summary of Significant AccountingPolicies for additional discussion.ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURENone.141ITEM 9A. CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and ProceduresWe maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required tobe disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rulesand forms, and to reasonably ensure that such information is accumulated and communicated to our management, including the ChiefExecutive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosurecontrols and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent allerrors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute,assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there areresource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in allcontrol systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, withinthe company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, andthat breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts ofsome persons, by collusion of two or more people, or by management override of the control. The design of any system of controls alsois based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design willsucceed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective controlsystem, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and makemodifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditionswarrant. An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of theperiod covered by this report. This evaluation was performed under the supervision and with the participation of our management,including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and ChiefFinancial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.Changes in Internal Control Over Financial ReportingThere have been no changes during the fourth quarter of 2015 that have materially affected, or are reasonably likely tomaterially affect, our internal control over financial reporting.142Management’s Report on Internal Control over Financial ReportingManagement of the Company is responsible for establishing and maintaining adequate internal control over financial reportingas defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Company’s internal controlover financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internalcontrol over financial reporting includes those policies and procedures that:(i)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositionsof the assets of the Company;(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts and expenditures of the Company are beingmade 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 theCompany’s assets that have a material effect on the financial statements.Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Eventhose systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation andpresentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may becomeinadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015. Inmaking this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the TreadwayCommission in Internal Control-Integrated Framework (2013 framework).Based on our assessment and those criteria, management believes that the Company maintained effective internal control overfinancial reporting as of December 31, 2015.The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internalcontrol over financial reporting. That report immediately follows this report.143Report of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of SM Energy Company and subsidiariesWe have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2015, based oncriteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (2013 framework) (the COSO criteria). SM Energy Company and subsidiaries’ management is responsible for maintainingeffective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reportingincluded in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express anopinion on the company’s internal control over financial reporting based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control overfinancial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness ofinternal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. Webelieve that our audit provides a reasonable basis for our opinion.A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of thecompany; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only inaccordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effecton the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projectionsof any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or procedures may deteriorate.In our opinion, SM Energy Company and subsidiaries maintained, in all material respects, effective internal control over financialreporting as of December 31, 2015, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theconsolidated balance sheets of SM Energy Company and subsidiaries as of December 31, 2015 and 2014, and the related consolidatedstatements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the periodended December 31, 2015 of SM Energy Company and subsidiaries and our report dated February 24, 2016 expressed an unqualifiedopinion thereon./s/ Ernst & Young LLPDenver, ColoradoFebruary 24, 2016144ITEM 9B. OTHER INFORMATIONNone.PART IIIITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCEThe information required by this Item concerning SM Energy’s Directors, Executive Officers, and corporate governance isincorporated by reference to the information provided under the captions “Proposal 1 - Election of Directors,” “Information aboutExecutive Officers,” and “Corporate Governance” in SM Energy’s definitive proxy statement for the 2016 annual meeting ofstockholders to be filed within 120 days from December 31, 2015.The information required by this Item concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 isincorporated by reference to the information provided under the caption “Section 16(a) Beneficial Ownership Reporting Compliance”in SM Energy’s definitive proxy statement for the 2016 annual meeting of stockholders to be filed within 120 days from December 31,2015.ITEM 11. EXECUTIVE COMPENSATIONThe information required by this Item is incorporated by reference to the information provided under the captions “ExecutiveCompensation” and “Director Compensation” in SM Energy’s definitive proxy statement for the 2016 annual meeting of stockholdersto be filed within 120 days from December 31, 2015.ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERSThe information required by this Item concerning security ownership of certain beneficial owners and management isincorporated by reference to the information provided under the caption “Security Ownership of Certain Beneficial Owners andManagement” in SM Energy’s definitive proxy statement for the 2016 annual meeting of stockholders to be filed within 120 days fromDecember 31, 2015.145Securities Authorized for Issuance Under Equity Compensation Plans. SM Energy has the Equity Plan under which options andshares of SM Energy common stock are authorized for grant or issuance as compensation to eligible employees, consultants, andmembers of the Board of Directors. Our stockholders have approved this plan. See Note 7 – Compensation Plans included in Part II,Item 8 of this report for further information about the material terms of our equity compensation plans. The following table is asummary of the shares of common stock authorized for issuance under the equity compensation plans as of December 31, 2015: (a) (b) (c)Plan category Number ofsecurities to beissued uponexercise ofoutstandingoptions, warrants,and rights Weighted-averageexercise price ofoutstanding options,warrants, and rights Number of securitiesremaining available forfuture issuance underequity compensationplans (excludingsecurities reflected incolumn (a))Equity compensation plans approved by securityholders: Equity Incentive Compensation Plan Stock options and incentive stock options (1) — $— Restricted stock (1)(3) 543,737 N/A Performance share units (1)(3)(4) 725,408 N/A Total for Equity Incentive Compensation Plan 1,269,145 $— 2,781,642Employee Stock Purchase Plan (2) — — 949,707Equity compensation plans not approved by securityholders — — —Total for all plans 1,269,145 $— 3,731,349____________________________________________(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, andmembers 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, and 2013 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2015,2014, and 2013 under the Equity Plan were 714,949, 464,641, and 632,939, 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 oftheir 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 thesix-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended toqualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 197,214, 83,136, and 77,427 in 2015, 2014, and 2013,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 toprovide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for theoutstanding RSUs and PSUs was $55.01 and $63.43, respectively. Please refer to Note 7 - Compensation Plans in Part II, Item 8 of this report foradditional 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-yearmultiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.146ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEThe information required by this Item is incorporated by reference to the information provided under the captions “CertainRelationships and Related Transactions” and “Corporate Governance” in SM Energy’s definitive proxy statement for the 2016 annualmeeting of stockholders to be filed within 120 days from December 31, 2015.ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICESThe information required by this Item is incorporated by reference to the information provided under the captions “IndependentRegistered Public Accounting Firm” and “Audit Committee Preapproval Policy and Procedures” in SM Energy’s definitive proxystatement for the 2016 annual meeting of stockholders to be filed within 120 days from December 31, 2015.147PART IVITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:Report of Independent Registered Public Accounting Firm88Consolidated Balance Sheets89Consolidated Statements of Operations90Consolidated Statements of Comprehensive Income (Loss)91Consolidated Statements of Stockholders’ Equity92Consolidated Statements of Cash Flows93Notes to Consolidated Financial Statements95All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to requiresubmission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.(b) Exhibits. The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:ExhibitNumberDescription 1.1Underwriting Agreement dated May 7, 2015, among SM Energy Company, and Wells Fargo Securities, LLC,Merrill Lynch, Pierce, Fenner, & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of theseveral underwriters (filed as Exhibit 1.1 to the registrant’s Current Report on Form 8-K filed on May 8, 2015, andincorporated herein by reference)2.1Acquisition and Development Agreement dated June 29, 2011 between SM Energy Company and Mitsui E&PTexas LP (filed as Exhibit 2.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011and incorporated herein by reference)2.2First Amendment to Acquisition and Development Agreement dated October 13, 2011 between SM EnergyCompany and Mitsui E&P Texas LP (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for thequarter ended September 30, 2011 and incorporated herein by reference)2.3***Purchase and Sale Agreement dated November 4, 2013, among SM Energy Company, EnerVest EnergyInstitutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest EnergyInstitutional Fund XIII-WIC, L.P. (filed as Exhibit 2.4 to the registrant’s Amendment to the Annual Report on Form10-K/A filed on May 9, 2014 for the year ended December 31, 2013, and incorporated herein by reference)2.4***Purchase and Sale Agreement dated July 29, 2014 between SM Energy Company and Baytex Energy USA LLC(filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014and incorporated herein by reference)3.1Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated hereinby reference)3.2Amended and Restated Bylaws of SM Energy Company, effective as of December 15, 2015 (filed as Exhibit 3.1 tothe registrant’s Current Report on Form 8-K filed on December 21, 2015, and incorporated herein by reference)4.1Indenture related to the 6.625% Senior Notes due 2019, dated as of February 7, 2011, by and between SM EnergyCompany, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s CurrentReport on Form 8-K filed on February 10, 2011, and incorporated herein by reference)1484.2Indenture related to the 6.50% Senior Notes due 2021, dated as of November 8, 2011, by and among SM EnergyCompany, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s CurrentReport on Form 8-K filed on November 10, 2011, and incorporated herein by reference)4.3Indenture related to the 6.50% Senior Notes due 2023, dated June 29, 2012, between SM Energy Company, asIssuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report onForm 8-K filed on July 3, 2012, and incorporated herein by reference)4.4Indenture related to the 5.0% Senior Notes due 2024, dated May 20, 2013, by and between SM Energy Company,as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s Current Report onForm 8-K filed on May 20, 2013, and incorporated herein by reference)4.5Indenture related to the 6.125% Senior Notes due 2022, dated November 17, 2014, by and between SM EnergyCompany, as issuer, and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to the registrant’s CurrentReport on Form 8-K filed on November 18, 2014, and incorporated herein by reference)4.6Indenture related to senior debt securities of SM Energy Company by and between SM Energy Company and U.S.Bank National Association, as trustee (filed as Exhibit 4.1 to the registrant’s Registration Statement on Form S-3filed on May 7, 2015 (Registration No. 333-203936) and incorporated herein by reference)4.72025 Notes Supplemental Indenture (filed as Exhibit 4.2 to the registrant’s Current Report on Form 8-K filed onMay 21, 2015, and incorporated herein by reference)4.82019 Notes Supplemental Indenture (filed as Exhibit 4.3 to the registrant’s Current Report on Form 8-K filed onMay 21, 2015 and incorporated herein by reference)10.1†Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s Registration Statement onForm S-8 (Registration No. 333-106438) and incorporated herein by reference)10.2†Incentive Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to the registrant’s RegistrationStatement on Form S-8 (Registration No. 333-106438) and incorporated herein by reference)10.3Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, SecurityAgreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, asAdministrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant’s Current Reporton Form 8-K filed on April 20, 2009, and incorporated herein by reference)10.4Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14,2009 (filed as Exhibit 10.3 to the registrant’s Current Report on Form 8-K filed on April 20, 2009, and incorporatedherein by reference)10.5†Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 tothe registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein byreference)10.6***Gas Services Agreement effective as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering LLC(filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010and incorporated herein by reference)10.7sNet Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 tothe registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated hereinby reference)10.8†Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed asExhibit 10.30 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, andincorporated herein by reference)10.9+SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of November 9, 2010(filed as Exhibit 10.31 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010,and incorporated herein by reference)14910.10Gas Gathering Agreement dated May 31, 2011 between Regency Field Services LLC and SM Energy Company(filed as Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, andincorporated herein by reference)10.11Gathering and Natural Gas Services Agreement effective as of April 1, 2011 between SM Energy Company andETC Texas Pipeline, Ltd. (filed as Exhibit 10.3 to the registrant’s Quarterly Report on Form 10-Q for the quarterended June 30, 2011, and incorporated herein by reference)10.12Gas Processing Agreement effective as of April 1, 2011 between ETC Texas Pipeline, Ltd. and SM EnergyCompany (filed as Exhibit 10.4 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30,2011, and incorporated herein by reference)10.13†Employee Stock Purchase Plan, As Amended and Restated as of June 10, 2011 (filed as Exhibit 10.5 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein byreference)10.14†Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filedas Exhibit 10.41 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, andincorporated herein by reference)10.15†Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filedas Exhibit 10.42 to the registrant’s Annual Report on Form 10-K filed for the year ended December 31, 2011, andincorporated herein by reference)10.16†Equity Incentive Compensation Plan, As Amended as of May 22, 2013 (filed as Annex A to the registrant’sSchedule 14A filed on April 11, 2013, and incorporated herein by reference)10.17Fifth Amended and Restated Credit Agreement dated April 12, 2013, among SM Energy Company, as Borrower,Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit10.1 to the registrant’s Current Report on Form 8-K filed on April 15, 2013, and incorporated herein by reference)10.18†Form of Performance Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.2 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)10.19†Form of Restricted Stock Unit Award Agreement as of July 31, 2013 (filed as Exhibit 10.3 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference)10.20†SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to theregistrant’s Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)10.21†Cash Bonus Plan, As Amended and Restated as of February 1, 2014 (filed as Exhibit 10.41 to the registrant’sAnnual Report on Form 10-K filed for the year ended December 31, 2013, and incorporated herein by reference)10.22†Section 162(m) Cash Bonus Plan, effective as of May 21, 2014 (filed as Exhibit 10.1 to the registrant’s CurrentReport on Form 8-K filed on May 28, 2014, and incorporated herein by reference)10.23*†Summary of Compensation Arrangements for Non-Employee Directors10.24Second Amendment to the Fifth Amended and Restated Credit Agreement dated December 10, 2014, among SMEnergy Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lendersparty thereto (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on December 16, 2014, andincorporated herein by reference)10.25Third Amendment to Fifth Amended and Restated Credit Agreement, dated May 20, 2015, among SM EnergyCompany, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed asExhibit 10.1 to the registrant’s Current Report on Form 8-K filed on May 27, 2015, and incorporated herein byreference)10.26Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated October 7, 2015, among SM EnergyCompany, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed asExhibit 10.1 to the registrant’s Current Report on Form 8-K filed on October 8, 2015, and incorporated herein byreference)15010.27Fifth Amendment to Fifth Amended and Restated Credit Agreement, dated November 11, 2015, among SM EnergyCompany, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders party thereto (filed asExhibit 10.1 to the registrant’s Current Report on Form 8-K filed on November 11, 2015, and incorporated hereinby reference)10.28Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s Current Report on Form8-K filed on October 20, 2015, and incorporated herein by reference)10.29*†Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 201610.30***Amendment to Amended and Restated Gas Gathering Agreement, effective as of September 1, 2015, by andbetween SM Energy Company and Regency Field Services LLC (filed as Exhibit 10.1 to the registrant’s CurrentReport on Form 8-K filed on September 15, 2015, and incorporated herein by reference)10.31Amendment to Amended and Restated Gas Gathering Agreement, effective as of February 1, 2016, by and betweenSM Energy Company and ETC Field Services LLC (filed as Exhibit 10.1 to the registrant’s Current Report on Form8-K filed on February 22, 2016, and incorporated herein by reference)12.1*Computation of Ratio of Earnings to Fixed Charges21.1*Subsidiaries of Registrant23.1*Consent of Ernst & Young LLP23.2*Consent of Ryder Scott Company L.P.24.1*Power of Attorney31.1*Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 200231.2*Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 200232.1**Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of200299.1*Ryder Scott Audit Letter101.INS*XBRL Instance Document101.SCH*XBRL Schema Document101.CAL*XBRL Calculation Linkbase Document101.LAB*XBRL Label Linkbase Document101.PRE*XBRL Presentation Linkbase Document101.DEF*XBRL Taxonomy Extension Definition Linkbase Document * Filed with this Form 10-K.** Furnished with this Form 10-K.***Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commissionpursuant to Rule 24b-2 under the Securities Exchange Act of 1934.†Exhibit constitutes a management contract or compensatory plan or agreement.sExhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change inthe name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms andconditions 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 technicalrevisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in thisdocument.(c) Financial Statement Schedules. See Item 15(a) above.151SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused thisreport to be signed on its behalf by the undersigned, thereunto duly authorized. SM ENERGY COMPANY (Registrant) Date:February 24, 2016By:/s/ JAVAN D. OTTOSON Javan D. Ottoson President and Chief Executive Officer (Principal Executive Officer)GENERAL POWER OF ATTORNEYKNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each ofJavan D. Ottoson and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution andresubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and allcapacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2015, and to file thesame, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, herebyratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtuehereof.Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons onbehalf of the registrant and in the capacities and on the dates indicated.Signature Title Date /s/ JAVAN D. OTTOSON President, Chief Executive Officer, and Director February 24, 2016Javan D. Ottoson (Principal Executive Officer) /s/ A. WADE PURSELL Executive Vice President and Chief FinancialOfficer February 24, 2016A. Wade Pursell (Principal Financial Officer) /s/ MARK T. SOLOMON Vice President - Controller and AssistantSecretary February 24, 2016Mark T. Solomon (Principal Accounting Officer) 152Signature Title Date /s/ WILLIAM D. SULLIVAN Chairman of the Board of Directors February 24, 2016William D. Sullivan /s/ LARRY W. BICKLE Director February 24, 2016Larry W. Bickle /s/ STEPHEN R. BRAND Director February 24, 2016Stephen R. Brand /s/ WILLIAM J. GARDINER Director February 24, 2016William J. Gardiner /s/ LOREN M. LEIKER Director February 24, 2016Loren M. Leiker /s/ RAMIRO G. PERU Director February 24, 2016Ramiro G. Peru /s/ JULIO M. QUINTANA Director February 24, 2016Julio M. Quintana /s/ ROSE M. ROBESON Director February 24, 2016Rose M. Robeson 153EXHIBIT 10.23SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORSThe following is a description of the standard arrangements pursuant to which directors of SM Energy are compensated forservices provided as a director, including additional amounts payable for committee participation:DIRECTOR COMPENSATIONEmployee directors do not receive additional compensation for serving on the Board of Directors or any committee.For service in 2015 - 2016 as it relates to the period from May 2015 through May 2016, target compensation for each memberof the Board of Directors has been set at $180,000 annually, plus a retainer paid in lieu of committee and attendance fees. As describedmore fully below, the actual value of compensation may be higher or lower depending on the results of the restricted stock componentof director compensation. Primary director compensation is in the form of stock grants and is fully described below. The retainercomponent of director compensation for non-employee directors consists of an annual retainer of $90,000 for committee and boardmeeting fees paid in SM Energy common stock or cash as selected by the director; provided that in the event any director attends inexcess of 30 Board and committee meetings in the aggregate during the period from May 2015 through May 2016, such director shallreceive $1,500 per meeting for each meeting in excess of 30. In addition, each non-employee director is reimbursed for expensesincurred in attending Board and committee meetings and director education programs.The committee chairs receive the cash payments identified in the list below in recognition of the additional workload of theirrespective committee assignments. These amounts are paid at the beginning of the annual service period. •Audit Committee - $20,000•Compensation Committee - $15,000•Nominating and Corporate Governance Committee - $10,000The stock compensation for non-employee directors is as follows:1)Annual compensation payable upon election to the Board by the stockholders, valued at $180,000. This resulted in agrant of restricted stock to each non-employee director of 3,308 shares of SM Energy common stock issued on May 20,2015, under SM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year boardservice period and carry a subsequent six month transfer restriction imposed by SM Energy.2)A retainer for the Non-Executive Chairman of the Board valued at $85,000. This resulted in a grant of 1,562 shares ofSM Energy common stock issued on May 20, 2015, under SM Energy's Equity Incentive Compensation Plan. Theseshares are earned over the one-year board service period and carry a subsequent six month transfer restriction imposedby SM Energy.3)Steven R. Brand, William J. Gardiner, Loren M. Leiker, Julio M. Quintana, Rose M. Robeson and William D. Sullivaneach elected to receive SM Energy common stock fortheir retainer, which resulted in a grant of 1,654 shares of SM Energy common stock issued on May 20, 2015, underSM Energy's Equity Incentive Compensation Plan. These shares are earned over the one-year Board service period andcarry a subsequent six month transfer restriction imposed by SM Energy. Larry W. Bickle and Ramiro G. Peru eachelected to receive a $90,000 cash payment for their retainer.EXHIBIT 10.29AMENDMENT NO. 3 TO THEPENSION PLAN FOR EMPLOYEES OF SM ENERGY COMPANYWHEREAS, SM Energy Company (the “Company”) maintains the Pension Plan for Employees of SM Energy Company (the“Plan”) for the benefit of certain of its employees; andWHEREAS, the Plan has been amended from time to time and was most recently amended and restated in its entirety, effectiveJanuary 1, 2010; andWHEREAS, pursuant to the authority in Section 10.1 of the Plan, the Plan may be amended at any time and from time to time;andWHEREAS, the Administrative Committee of the Plan has recommended to the Board of Directors of the Company to amendthe Plan’s eligibility provisions to provide that no individual will be eligible to participate effective on and after January 1, 2016, andthe Company desires to make such change at this time.NOW, THEREFORE, effective January 1, 2016, the Plan is amended as hereinafter set forth:Section 2.2 of the Plan is hereby amended in its entirety to provide as follows:2.2 ELIGIBILITY TO PARTICIPATE.(a)Each Employee who was an Active Participant immediately prior to the Effective Date and is a Covered Employee onthe Effective Date will continue to be an Active Participant as of the Effective Date.(a)Each other Employee will become an Active Participant on the first day of the calendar month coincident with or nextfollowing the date on which such Employee attains Age 21 and completes one Year of Eligibility Service, if then aCovered Employee.(b)A Participant (or a former Participant) who has a Separation from Service and who is later reemployed as a CoveredEmployee will become an Active Participant as of the date on which he or she first again completes an Hour of Serviceas a Covered Employee, but, if he or she has had a Break in Service, only if he or she (1) had any vested interest in hisor her Accrued Benefit as of the prior Separation from Service or (2) again completes one Hour of Service at a timewhen the consecutive Breaks in Service do not equal or exceed the greater of five, or the number of Years of EligibilityService credit prior to the Break in Service. Amendment No. 3 to the Pension Plan for Employees of SM Energy Company 12/2015 1Prepared by Holland & Hart LLP (c)If an individual is not a Covered Employee on the date on which the individual would otherwise become an ActiveParticipant (but for the fact that such individual is not then a Covered Employee), such individual will become an ActiveParticipant as of the first date thereafter on which the individual becomes a Covered Employee; but, if there was a Breakin Service, only if the individual (1) had any vested interest in his or her Accrued Benefit as of the prior Separation fromService or (2) again completes one Hour of Service at a time when his or her consecutive Breaks in Service do not equalor exceed the greater of five, or the number of Years of Eligibility Service prior to the Break in Service.(d)Notwithstanding the above, effective January 1, 2016, the Plan is frozen with respect to participation. Accordingly,Employees hired on and after January 1, 2015 will not be eligible to participate in the Plan.IN WITNESS WHEREOF, SM Energy Company has caused this Amendment No. 3 to be executed this 28th day of December,2015 by a duly authorized officer of the Company.SM ENERGY COMPANYBy: /s/ John MonarkTitle: Senior Vice President – Human Resources Amendment No. 3 to the Pension Plan for Employees of SM Energy Company 12/2015 2Prepared by Holland & Hart LLP EXHIBIT 12.1SM Energy CompanyRatio of Earnings to Fixed Charges Year Ended December 31, 20152014201320122011 (in thousands, except ratios) Pretax income (loss) from continuingoperations$(722,861)$1,064,699$278,611$(83,517)$339,001 Add: Fixed charges155,510117,147102,75877,84158,030Add: Amortization of capitalizedinterest9,11611,44811,7849,0955,107Less: Capitalized interest(25,051)(16,165)(10,952)(12,135)(10,785)Earnings before fixed charges$(583,286)$1,177,129$382,201$(8,716)$391,353 Fixed charges: Interest expense (1)$128,149$98,554$89,711$63,720$45,849Capitalized interest25,05116,16510,95212,13510,785Interest expense component of rent (2)2,3102,4282,0951,9861,396Total fixed charges$155,510$117,147$102,758$77,841$58,030 Ratio of earnings to fixed charges—10.03.7—6.7Insufficient coverage$738,796$—$—$86,557$—(1) Includes amortization of discount and deferred financing costs.(2) Represents a reasonable approximation of the rental factor.EXHIBIT 21.1SUBSIDIARIESOFSM ENERGY COMPANYA.Wholly-owned subsidiaries of SM Energy Company, a Delaware corporation:1. SMT Texas LLC, a Colorado limited liability company2. Energy Leasing, Inc., an Oklahoma corporation3. Belring GP LLC, a Delaware limited liability company4. St. Mary Energy Louisiana LLC, a Delaware limited liability company5. Hilltop Investments, a Colorado general partnership6. Parish Ventures, a Colorado general partnership7. Green Canyon Offshore LLC, a Delaware limited liability company.B.Partnership or limited liability company interests held by SM Energy Company:1.Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)2.1977 H.B Joint Account, a Colorado general partnership (8%)3.1976 H.B Joint Account, a Colorado general partnership (9%)4.1974 H.B Joint Account, a Colorado general partnership (4%)C. Partnership interests held by SMT Texas, LLC:1.St. Mary Land East Texas LP, a Texas limited partnership (99%) (the remaining 1% interest is held by SM EnergyCompany)EXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-106438, 333-35352, and 333-88780 on Form S-8, Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740,333-170351 and 333-194305 on Form S-8, and Registration Statement No. 333-203936 on Form S-3 of our reports dated February 24,2016, with respect to the consolidated financial statements of SM Energy Company and subsidiaries, and the effectiveness of internalcontrol over financial reporting of SM Energy Company and subsidiaries, included in this Annual Report (Form 10-K) for the yearended December 31, 2015./s/ ERNST & YOUNG LLPDenver, ColoradoFebruary 24, 2016EXHIBIT 23.2CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSThe undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report onForm 10-K of SM Energy Company for the year ended December 31, 2015. We hereby further consent to the use of informationcontained in our reports, and the use of our audit letter, as of December 31, 2015, relating to estimates of revenues from SM EnergyCompany's oil, gas, and NGL reserves. We further consent to the incorporation by reference thereof into SM Energy Company’s Post-Effective Amendment No. 1 to Registration Statement Nos. 333-30055, 333-106438, 333-35352, and 333-88780 on Form S-8,Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351 and 333-194305 on Form S-8, andRegistration Statement No. 333-203936 on Form S-3./s/ RYDER SCOTT COMPANY, L.P.Denver, COFebruary 24, 2016EXHIBIT 31.1CERTIFICATIONI, Javan D. Ottoson, certify that:1.I have reviewed this annual report on Form 10-K of SM Energy Company;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)and 15d-15(f)) for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed underour supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financialstatements for external purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant'smost recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 24, 2016/s/ JAVAN D. OTTOSONJavan D. OttosonPresident and Chief Executive OfficerEXHIBIT 31.2CERTIFICATIONI, A. Wade Pursell, certify that:1.I have reviewed this annual report on Form 10-K of SM Energy Company;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary tomake the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periodcovered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as definedin Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)and 15d-15(f)) for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those entities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed underour supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financialstatements for external purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions aboutthe effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on suchevaluation; and(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant'smost recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant'sinternal control over financial reporting.Date: February 24, 2016/s/ A. WADE PURSELLA. Wade PursellExecutive Vice President and Chief Financial OfficerEXHIBIT 32.1CERTIFICATIONPURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report on Form 10-K of SM Energy Company (the “Company”) for the fiscal year ended December 31, 2015as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Javan D. Ottoson, as President and Chief Executive Officerof the Company, and A. Wade Pursell, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant toand solely for the purpose of 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge andbelief, that:(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or78o(d)); and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany./s/ JAVAN D. OTTOSONJavan D. OttosonPresident and Chief Executive OfficerFebruary 24, 2016/s/ A. WADE PURSELLA. Wade PursellExecutive Vice President and Chief Financial OfficerFebruary 24, 2016EXHIBIT 99.1SM ENERGY COMPANYEstimatedFuture ReservesAttributable to CertainLeasehold InterestsSEC ParametersAs ofDecember 31, 2015/s/ Michael F. Stell /s/ James L. BairdMichael F. Stell, P.E. James L. BairdTBPE License No. 56416 Colorado License No. 41521Advising Senior Vice President Managing Senior Vice PresidentRYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSJanuary 4, 2016Ms. Kelly SuttonManager of ReservesSM Energy Company1775 Sherman Street, Suite 1200Denver, Colorado 80203Ladies & Gentlemen:At the request of SM Energy Company (SM Energy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reservesaudit of the estimates of the proved reserves as of December 31, 2015 prepared by SM Energy’s engineering and geological staffbased on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained inTitle 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the FederalRegister (SEC regulations). Our third party reserves audit, completed on January 2, 2016 and presented herein, was prepared forpublic disclosure by SM Energy in filings made with the SEC in accordance with the disclosure requirements set forth in the SECregulations. The estimated reserves shown herein represent SM Energy’s estimated net reserves attributable to the leaseholdinterests in certain properties owned by SM Energy and the portion of those reserves reviewed by Ryder Scott, as of December31, 2015. The properties reviewed by Ryder Scott incorporate 3,013 SM Energy reserve determinations and are located in thestates of Louisiana, North Dakota, Texas and Wyoming.The properties reviewed by Ryder Scott account for a portion of SM Energy’s total net proved reserves as of December 31,2015. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by Ryder Scottaddresses 81.6 percent of the total proved developed net liquid hydrocarbon reserves, 86.9 percent of the total proved developednet gas reserves, 86.3 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 90.3 percent of the totalproved undeveloped net gas reserves of SM Energy.As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewingcertain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by othersand the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of thedata relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriateto the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our opinionthat the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves as ofDecember 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties asestimated by SM Energy are, in theSUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258SM Energy CompanyJanuary 4, 2016Page 2aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.The estimated reserves presented in this report are related to hydrocarbon prices. SM Energy has informed us that in thepreparation of their reserve and income projections, as of December 31, 2015, they used average prices during the 12-monthperiod prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by theSEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report. The net reserves as estimated by SM Energy attributable to SM Energy's interest in properties that wereviewed and the reserves of properties that we did not review are summarized as follows:SEC PARAMETERSEstimated Net ReservesCertain Leasehold Interests ofSM Energy CompanyAs of December 31, 2015 Proved Developed Total Producing Non-Producing Undeveloped ProvedNet Reserves of PropertiesAudited by Ryder Scott Oil/Condensate - MBarrels 53,478 1,136 52,958 107,572 Plant Products - MBarrels 56,695 609 53,627 110,931 Gas - MMCF 555,697 4,113 559,282 1,119,092 Net Reserves of PropertiesNot Audited by Ryder Scott Oil/Condensate - MBarrels 20,340 685 16,667 37,692 Plant Products - MBarrels 3,471 700 262 4,433 Gas - MMCF 76,988 7,571 60,397 144,956 Total Net Reserves Oil/Condensate - MBarrels 73,818 1,821 69,625 145,264 Plant Products - MBarrels 60,166 1,309 53,889 115,364 Gas - MMCF 632,685 11,684 619,679 1,264,048Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis”expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reservesare located. MBarrels means thousand barrels of oil.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 3Reserves Included in This ReportIn our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities andExchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a)entitled “Petroleum Reserves Definitions” is included as an attachment to this report.The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves StatusDefinitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in andbehind pipe categories.Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. At SM Energy’s request, this report addresses onlythe proved reserves attributable to the properties reviewed herein.Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves includedherein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when basedon deterministic methods, as a “high degree of confidence that the quantities will be recovered.”Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR)with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates ofproved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical oreconomic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as beingexact quantities, and if recovered could be more or less than the estimated amounts.Audit Data, Methodology, Procedure and AssumptionsThe estimation of reserves involves two distinct determinations. The first determination results in the estimation of thequantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with thoseestimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generallyaccepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-basedmethods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserveevaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination ofmethods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience andengineering dataRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 4available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated andthe stage of development or producing maturity of the property.In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this datamay indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range inthe quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of thereserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discreteincremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is thecategorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimatedquantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actuallyrecovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reservesthat are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to berecovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered thanprobable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions asnoted above.Estimates of reserves quantities and their associated reserve categories may be revised in the future as additionalgeoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reservecategories may also be revised due to other factors such as changes in economic conditions, results of future operations, effectsof regulation by governmental agencies or geopolitical or economic risks as previously noted herein.The proved reserves, prepared by SM Energy, for the properties that we reviewed were estimated by performancemethods, the volumetric method, analogy, or a combination of methods. Approximately 100 percent of the proved producingreserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods or acombination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balanceand/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November orearly December 2015, in those cases where such data were considered to be definitive. The data utilized in this analysis werefurnished to Ryder Scott by SM Energy or obtained from public data sources and were considered sufficient for the purposethereof.Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed wereestimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well andseismic data furnished to Ryder Scott by SM Energy for our review or which we have obtained from public data sources that wereavailable through December 2015. The data utilized from the analogues in conjunction with well and seismic data incorporated intothe volumetric analysis were considered sufficient for the purpose thereof.To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are consideredincluding, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data whichcannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of futureproduction rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economicallyproducible from a given date forward based on existing economic conditions including the prices and costs at which economicproducibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the saleof production and the operating costs and other costs relating to such productionRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 5may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adoptedby the SEC, omitted from consideration in conducting this review.As stated previously, proved reserves must be anticipated to be economically producible from a given date forward basedon existing economic conditions including the prices and costs at which economic producibility from a reservoir is to bedetermined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, wehave reviewed certain primary economic data utilized by SM Energy relating to hydrocarbon prices and costs as noted herein.The hydrocarbon prices furnished by SM Energy for the properties reviewed by us are based on SEC price parametersusing the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmeticaverages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined bycontractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinableescalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices wereadjusted to the 12-month unweighted arithmetic average as previously described.The initial SEC hydrocarbon prices in effect on December 31, 2015 for the properties reviewed by us were determinedusing the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbonsare sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizesthe “benchmark prices” and “price reference” used by SM Energy for the geographic area reviewed by us. In certain geographicareas, the price reference and benchmark prices may be defined by contractual arrangements.The product prices which were actually used by SM Energy to determine the future gross revenue for each propertyreviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market,referred to herein as “differentials.” The differentials used by SM Energy were accepted as factual data and reviewed by us for theirreasonableness; however, we have not conducted an independent verification of the data used by SM Energy.The table below summarizes SM Energy’s net volume weighted benchmark prices adjusted for differentials for theproperties reviewed by us and referred to herein as SM Energy’s “average realized prices.” The average realized prices shown inthe table below were determined from SM Energy’s estimate of the total future gross revenue before production taxes for theproperties reviewed by us and SM Energy’s estimate of the total net reserves for the properties reviewed by us for the geographicarea. The data shown in the table below is presented in accordance with SEC disclosure requirements for the geographic areareviewed by us.Geographic AreaProductPriceReferenceAverageBenchmarkPricesAverageRealizedPrices North America United StatesOil/CondensateWTI, Cushing$50.28/Bbl$42.86Bbl NGLsPropane, MT. Belvieu$20.20/Bbl$17.01Bbl GasHenry Hub$2.59/MMBTU$2.58/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in SM Energy’sindividual property evaluations.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 6Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed.The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.Operating costs furnished by SM Energy are based on the operating expense reports of SM Energy and include only thosecosts directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of generaland administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include anappropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties includethe COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operatingcosts furnished by SM Energy were accepted as factual data and reviewed by us for their reasonableness; however, we have notconducted an independent verification of the data used by SM Energy. No deduction was made for loan repayments, interestexpenses, or exploration and development prepayments that were not charged directly to the leases or wells.Development costs furnished by SM Energy are based on authorizations for expenditure for the proposed work or actualcosts for similar projects. The development costs furnished by SM Energy were accepted as factual data and reviewed by us fortheir reasonableness; however, we have not conducted an independent verification of the data used by SM Energy. The estimatednet cost of abandonment and salvage was included by SM Energy for properties where abandonment costs and salvage weresignificant. SM Energy’s estimates of the net abandonment costs were accepted without independent verification.The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporatedherein in accordance with SM Energy’s plans to develop these reserves as of December 31, 2015. The implementation of SMEnergy’s development plans as presented to us is subject to the approval process adopted by SM Energy’s management. As theresult of our inquiries during the course of our review, SM Energy has informed us that the development activities for the propertiesreviewed by us have been subjected to and received the internal approvals required by SM Energy’s management at theappropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities maystill be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrativeapprovals external to SM Energy. Additionally, SM Energy has informed us that they are not aware of any any legal, regulatory, orpolitical obstacles that would significantly alter their plans. While these plans could change from those under existing economicconditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluationCurrent costs used by SM Energy were held constant throughout the life of the properties.SM Energy’s forecasts of future production rates are based on historical performance from wells currently on production. Ifno production decline trend has been established, future production rates were held constant, or adjusted for the effects ofcurtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied todepletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future productionrates.Test data and other related information were used by SM Energy to estimate the anticipated initial production rates for thosewells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at ananticipated date furnished by SM Energy. Wells or locations that are not currently producing may start producing earlier or laterthan anticipated in SM Energy’s estimates due to unforeseen factors causing a change in the timing to initiate production. SuchfactorsRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 7may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/orconstraints set by regulatory bodies.The future production rates from wells currently on production or wells or locations that are not currently producing may bemore or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related tosurface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/orallowables or other constraints set by regulatory bodies.SM Energy’s operations may be subject to various levels of governmental controls and regulations. These controls andregulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to producehydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxesand levies including income tax and are subject to change from time to time. Such changes in governmental regulations andpolicies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differsignificantly from the estimated quantities.The estimates of proved reserves presented herein were based upon a review of the properties in which SM Energy ownsan interest; however, we have not made any field examination of the properties. No consideration was given in this report topotential environmental liabilities that may exist nor were any costs included by SM Energy for potential liabilities to restore andclean up damages, if any, caused by past operating practices.Certain technical personnel of SM Energy are responsible for the preparation of reserve estimates on new properties andfor the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data andmaintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to theirworkpapers and supporting data in the course of our audit.SM Energy has informed us that they have furnished us all of the material accounts, records, geological and engineeringdata, and reports and other data required for this investigation. In performing our audit of SM Energy’s forecast of future provedproduction, we have relied upon data furnished by SM Energy with respect to property interests owned, production and well testsfrom examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processingfees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs andsalvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural andisochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for itsreasonableness; however, we have not conducted an independent verification of the data furnished by SM Energy. The datadescribed herein were accepted as authentic and sufficient for determining the reserves unless, during the course of ourexamination, a matter of question came to our attention in which case the data were not accepted until all questions weresatisfactorily resolved. We consider the factual data furnished to us by SM Energy to be appropriate and sufficient for the purposeof our review of SM Energy’s estimates of reserves. In summary, we consider the assumptions, data, methods and analyticalprocedures used by SM Energy and as reviewed by us appropriate for the purpose hereof, and we have used all such methodsand procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 8Audit OpinionBased on our review, including the data, technical processes and interpretations presented by SM Energy, it is our opinionthat the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves as ofDecember 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties asestimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as setforth in the SPE auditing standards.We were in reasonable agreement with SM Energy’s estimates of proved reserves for the properties which we reviewed;although in certain cases there was more than an acceptable variance between SM Energy’s estimates and our estimates due to adifference in interpretation of data or due to our having access to data which were not available to SM Energy when its reserveestimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for theproperties that we reviewed fairly reflects the estimated net reserves owned by SM Energy.Other PropertiesOther properties, as used herein, are those properties of SM Energy which we did not review. The proved net reservesattributable to the other properties account for 16.2 percent of the total proved net liquid hydrocarbon reserves and 11.5 percent ofthe total proved net gas reserves based on estimates prepared by SM Energy as of December 31, 2015. The other propertiesrepresent 19.6 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC astaken from reserve and income projections prepared by SM Energy as of December 31, 2015.The same technical personnel of SM Energy were responsible for the preparation of the reserve estimates for theproperties that we reviewed as well as for the properties not reviewed by Ryder Scott.Standards of Independence and Professional QualificationRyder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting servicesthroughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; andCalgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firmand the large number of clients for which we provide services, no single client or job represents a material portion of our annualrevenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separateand independent from the operating and investment decision-making process of our clients. This allows us to bring the highest levelof independence and objectivity to each engagement for our services.Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused onthe subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on thesubject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participatingin ongoing continuing education.Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have receivedprofessional accreditation in the form of a registered or certified professional engineer’s license or a registered or certifiedprofessional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 9We are independent petroleum engineers with respect to SM Energy. Neither we nor any of our employees have anyfinancial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on ourestimates of reserves for the properties which were reviewed.The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists andengineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible foroverseeing the review of the reserves information discussed in this report, are included as attachments to this letter.Terms of UsageThe results of our third party audit, presented in report form herein, were prepared in accordance with the disclosurerequirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SMEnergy.SM Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SM Energy hascertain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K isincorporated by reference. We have consented to the incorporation by reference thereof into the Company's RegistrationStatements on Form S-8, of the references to our name as well as to the references to our third party report for SM Energy, whichappears in the December 31, 2015 annual report on Form 10-K of SM Energy. Our written consent for such use is included as aseparate exhibit to the filings made with the SEC by SM Energy.We have provided SM Energy with a digital version of the original signed copy of this report letter. In the event there are anydifferences between the digital version included in filings made by SM Energy and the original signed report letter, the originalsigned report letter shall control and supersede the digital version.The data and work papers used in the preparation of this report are available for examination by authorized parties in ouroffices. Please contact us if we can be of further service.Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580/s/ Michael F. StellMichael F. Stell, P.E.TBPE License No. 56416Advising Senior Vice President /s/ James L. BairdJames L. BairdColorado License No. 41521Managing Senior Vice PresidentRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 10RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 1Professional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate ofthe reserves, future production and income.Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and isresponsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studiesworldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and LandmarkConcurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the RyderScott Company website at www.ryderscott.com/Company/Employees.Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of ScienceDegree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in theState of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineersrequires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics,which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours offormalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the UnitedStates Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, FinalRule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training aswell as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEEPetroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods,procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internallypresented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerningthe implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the variousproductive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, andethics training. For each year starting 2011 through 2015, as of the date of this report, Mr. Stell has 20 hours of continuingeducation hours relating to reserves, reserve evaluations, and ethics.Based on his educational background, professional training and over 30 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and ReservesAuditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”promulgated by the Society of Petroleum Engineers as of February 19, 2007.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 4, 2016Page 1Professional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. James Larry Baird was the primary technical person responsible for overseeing the estimate ofthe reserves.Mr. Baird, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and alsoserves as Manager of the Denver office, responsible for coordinating and supervising staff and consulting engineers of thecompany in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Baird served in a number ofengineering positions with Gulf Oil Corporation (1970-1973), Northern Natural Gas (1973-1975) and Questar Exploration &Production (1975-2006). For more information regarding Mr. Baird’s geographic and job specific experience, please refer to theRyder Scott Company website at www.ryderscott.com/Experience/Employees.Mr. Baird earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970 and is aregistered Professional Engineer in the States of Colorado and Utah. He is also a member of the Society of Petroleum Engineers.In addition to gaining experience and competency through prior work experience, several State Boards of Professional Engineersrequire a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics,which Mr. Baird fulfills as part of his registration in two states. As part of his continuing education, Mr. Baird attends internallypresented training as well as public forums relating to the definitions and disclosure guidelines contained in the United StatesSecurities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and FinalRule released January 14, 2009 in the Federal Register. Mr. Baird attends additional hours of formalized external training coveringsuch topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleumeconomics evaluation methods, procedures and software and ethics for consultants.Based on his educational background, professional training and more than 45 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Baird has attained the professional qualifications as a Reserves Estimator and ReservesAuditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”promulgated by the Society of Petroleum Engineers as of February 19, 2007.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES DEFINITIONSAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)PREAMBLEOn January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oiland Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 ofRegulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifiesIndustry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for allfilings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for thecomplete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italicsherein).Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31,2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gasreserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gasresources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unlesssuch information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.Reserves estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change.Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include allmethods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples ofsuch methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use ofmiscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleumtechnology continues to evolve.Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulationsare considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction methodapplied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseammethane (CBM/CSM), basin-RYDER SCOTT COMPANY PETROLEUM CONSULTANTScentered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may requirespecialized extraction technology and/or significant processing prior to sale.Reserves do not include quantities of petroleum being held in inventory.Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum fromdifferent reserves categories.RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, orthere must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement theproject.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults untilthose reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that areclearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, ornegative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscoveredaccumulations).PROVED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscienceand engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, fromknown reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time atwhich contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless ofwhether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with itand to contain economically producible oil or gas on the basis of available geoscience and engineering data. PROVED RESERVES (SEC DEFINITIONS) CONTINUED(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technologyestablishes a lower contact with reasonable certainty.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential existsfor an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only ifgeoscience, engineering, or performance data and reliable technology establish the higher contact with reasonablecertainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in thereservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which theproject or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmentalentities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Theprice shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determinedas an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices aredefined by contractual arrangements, excluding escalations based upon future conditions.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESPage 1PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)andPETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)Sponsored and Approved by:SOCIETY OF PETROLEUM ENGINEERS (SPE)WORLD PETROLEUM COUNCIL (WPC)AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)Reserves status categories define the development and producing status of wells and reservoirs. Reference should bemade to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the followingreserves status definitions are based on excerpts from the original documents (direct passages excerpted from theaforementioned SEC and SPE-PRMS documents are denoted in italics herein).DEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the requiredequipment is relatively minor compared to the cost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if theextraction is by means not involving a well.Developed Producing (SPE-PRMS Definitions)While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at thetime of the estimate.Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-ProducingDeveloped Non-Producing Reserves include shut-in and behind-pipe reserves.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESPage 2Shut-InShut-in Reserves are expected to be recovered from:(1)completion intervals which are open at the time of the estimate, but which have not started producing;(2)wells which were shut-in for market conditions or pipeline connections; or(3)wells not capable of production for mechanical reasons.Behind-PipeBehind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completionwork or future re-completion prior to start of production.In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a newwell.UNDEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves asfollows:Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that arereasonably certain of production when drilled, unless evidence using reliable technology exists thatestablishes reasonable certainty of economic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has beenadopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify alonger time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which anapplication of fluid injection or other improved recovery technique is contemplated, unless such techniques havebeen proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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