SM Energy Company Annual Report 2014

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, 2014oro 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 66,163,202 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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, of $84.10 per share, as reported on the New York Stock Exchange; was$5,564,325,288. 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 18, 2015, the registrant had 67,463,060 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 2015annual meeting of stockholders to be filed within 120 days after December 31, 2014.1TABLE OF CONTENTSITEM PAGE PART I ITEMS 1. and 2.BUSINESS and PROPERTIES4 General4 Strategy4 Significant Developments in 20144 Outlook for 20155 Core Operational Areas6 Reserves8 Production12 Productive Wells13 Drilling and Completion Activity13 Acreage14 Delivery Commitments14 Major Customers15 Employees and Office Space15 Title to Properties15 Seasonality16 Competition16 Government Regulations16 Cautionary Information about Forward-Looking Statements21 Available Information23 Glossary of Oil and Gas Terms24ITEM 1A.RISK FACTORS29ITEM 1B.UNRESOLVED STAFF COMMENTS51ITEM 3.LEGAL PROCEEDINGS51ITEM 4.MINE SAFETY DISCLOSURES51 PART II52ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES52ITEM 6.SELECTED FINANCIAL DATA55ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS58 Overview of the Company58 Financial Results of Operations and Additional Comparative Data66 Comparison of Financial Results and Trends between 2014 and 201369 Comparison of Financial Results and Trends between 2013 and 201272 Overview of Liquidity and Capital Resources74 Critical Accounting Policies and Estimates80 Accounting Matters83 Environmental83 Non-GAAP Financial Measures842TABLE OF CONTENTS(Continued)ITEM PAGEITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUTMARKET RISK (included within the content of ITEM 7)85ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA87ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTING AND FINANCIAL DISCLOSURE142ITEM 9A.CONTROLS AND PROCEDURES142ITEM 9B.OTHER INFORMATION146 PART III146ITEM 10.DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATEGOVERNANCE146ITEM 11.EXECUTIVE COMPENSATION146ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIALOWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS146ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,AND DIRECTOR INDEPENDENCE148ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES148 PART IV149ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES1493PART 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,” respectively, throughout thedocument) in onshore North America. We were founded in 1908 and incorporated in Delaware in 1915. Our initial public offering ofcommon stock was 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 build our ownership and operatorship of North American oil, gas, and NGL producing assets thathave high operating margins and significant opportunities for additional economic investment. We pursue opportunities through bothacquisitions and exploration, and seek to maximize the value of our assets through industry leading technology application andoutstanding operational execution. We are returns focused and maintain a simple, strong balance sheet through a conservative approachto leverage.Significant Developments in 2014•Resource Play Delineation and Development Results in Record Production and Record Year-End Proved Reserve Estimates.Our estimated proved reserves increased 28 percent to 547.7 MMBOE at December 31, 2014, from 428.7 MMBOE atDecember 31, 2013. We added 143.9 MMBOE through drilling activities during the year, led by our efforts in our EagleFord shale play in south Texas and our Bakken/Three Forks play in North Dakota. Our proved reserve life increased to 9.9years in 2014 compared to 8.9 years in 2013. We also achieved record levels of production in 2014. Our average dailyproduction was composed of 45.6 MBbl of oil, 419.0 MMcf of gas, and 35.6 MBbl of NGLs for an average equivalentproduction rate of 151.1 MBOE per day, which was an increase of 14 percent from an average of 132.4 MBOE per day in2013. Costs incurred for drilling and exploration activities, excluding acquisitions, increased 36 percent to $2.1 billion in2014 when compared to 2013. Please refer to Core Operational Areas below for additional discussion concerning our 2014estimated proved reserves, production, and capital investment.•Acquisition Activity. During 2014, we acquired a total of 21.9 MMBOE of proved reserves through multiple transactions forconsideration of approximately $544.6 million in cash plus approximately 7,000 net acres of non-core assets in our RockyMountain region. Through these acquisitions, we added approximately 74,000 net acres in our Gooseneck area in DivideCounty, North Dakota and approximately 38,000 net acres in our Powder River Basin program in Wyoming.•Volatility and Decline in Commodity Prices. Our financial condition and results of operations are significantly affected bythe prices we receive for oil, gas, and NGLs, which can fluctuate dramatically.4Oil prices drastically declined in late 2014. The daily NYMEX spot price ranged from a high of $107.62 per Bbl in July to alow of $53.27 per Bbl in December. Oil prices declined further subsequent to year end 2014, dropping to a low of $44.45per Bbl in January 2015. The average NYMEX price decreased to $93.03 per Bbl in 2014 compared to $97.99 per Bbl in2013.Natural gas prices have been under downward pressure due to high levels of supply in recent years and were volatile during2014. The daily NYMEX spot price improved early in 2014 with a high of $7.92 per MMBtu in March and then droppedsignificantly to a low of $2.75 per MMBtu in December. Gas prices declined further subsequent to year end 2014, droppingto a low of $2.55 per MMBtu in February 2015. The average NYMEX price increased in 2014 to $4.35 per MMBtucompared to $3.73 per MMBtu in 2013.NGL prices decreased in 2014 in line with the steep decline in oil prices. The monthly OPIS NGL price reached a high of$48.43 per Bbl in February and a low of $22.44 per Bbl in December. NGL prices declined further subsequent to year end2014, dropping to a low of $20.03 per Bbl in January 2015. The average OPIS price decreased in 2014 to $38.93 per Bblcompared to $40.44 per Bbl in 2013.•Impairments. We recorded impairment of proved properties expense of $84.5 million and abandonment and impairment ofunproved properties expense of $75.6 million for the year ended December 31, 2014. Impairments recorded in 2014 were aresult of the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration anddelineation wells in certain prospects in our South Texas & Gulf Coast and Permian regions.Outlook for 2015We view 2015 as a year of transition as the broader oil and gas industry adjusts to lower oil prices. Exploration and productioncompanies are reducing drilling and completion activity, which we expect to result in service companies lowering the price of theirservices. Our plan for 2015 is to scale down activity over the course of the year while preserving the value of our assets and protectingthe strength of our balance sheet. Our goal is to be well positioned entering 2016 in what we expect will be a stronger commodity priceand lower service cost environment, while having the strength and flexibility to adapt should industry conditions worsen.Our capital program for 2015 will be approximately $1.2 billion, of which approximately $1.0 billion will be invested in drillingand completion activities. We expect to focus 85 percent of our drilling and completion capital on our core development programs inthe Eagle Ford shale and the Bakken/Three Forks formations. The remaining capital is being allocated to the construction of facilities,leasehold acquisitions, exploration overhead, and geological and geophysical costs. Please refer to Outlook for 2015 under Part II, Item7 of this report for additional discussion concerning our capital plans for 2015.5Core Operational AreasOur operations are concentrated in four onshore operating areas in the United States. The following table summarizes estimatedproved reserves, PV-10, production, and costs incurred in oil and gas activities for the year ended December 31, 2014, for our coreoperating areas:South Texas &Gulf Coast RockyMountain Permian Mid-Continent Total (1)Proved Reserves Oil (MMBbl)64.5 91.5 13.5 0.2 169.7Gas (Bcf)1,193.3 89.6 38.9 144.8 1,466.5NGLs (MMBbl)131.2 2.0 — 0.4 133.5MMBOE (1)394.6 108.4 20.0 24.7 547.7Relative percentage72% 20% 4% 4% 100%Proved Developed %48% 56% 76% 83% 52%PV-10 (in millions) (2) Proved Developed$2,942.8 $1,651.5 $440.8 $217.9 $5,253.0Proved Undeveloped1,593.0 699.0 55.5 16.4 2,363.9Total Proved$4,535.8 $2,350.5 $496.3 $234.3 $7,616.9Relative percentage60% 31% 6% 3% 100%Production Oil (MMBbl)7.1 7.4 2.0 0.1 16.7Gas (Bcf)121.6 7.0 4.5 19.8 152.9NGLs (MMBbl)12.8 0.1 — 0.1 13.0MMBOE (1)40.2 8.7 2.8 3.5 55.1Avg. Daily Equivalents(MBOE/d)110.1 23.9 7.6 9.5 151.1Relative percentage73% 16%5% 6% 100%Costs Incurred (in millions)(3)$1,187.8 $1,241.8 $195.4 $58.9 $2,711.7____________________________________________(1)Totals may not sum or recalculate due to rounding.(2)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.(3)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.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 180,000 netacres. Our operated program accounts for approximately 75 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.In addition, we continued to evaluate an emerging new venture play in east Texas in 2014. We have approximately 215,000 netacres that provide opportunities in the Austin Chalk, Woodbine, and Eagle Ford shale intervals. During 2014, we constructed agathering system to allow for longer-term production tests on our wells.6We deployed a significant amount of capital in our South Texas & Gulf Coast region in 2014 in our operated and outside-operated Eagle Ford shale programs. Costs incurred increased to $1.2 billion in 2014 from $849.4 million in 2013. Estimated provedreserves at year-end 2014 increased 27 percent from 311.2 MMBOE at year-end 2013. We added approximately 105.8 MMBOE ofestimated proved reserves through drilling activities. During 2012, 2013, and early 2014, we were carried for substantially all of ourdrilling and completion costs in our outside-operated Eagle Ford program pursuant to our Acquisition and Development Agreementwith Mitsui E&P Texas LP (“Mitsui”), an indirect subsidiary of Mitsui & Co., Ltd. (the “Acquisition and Development Agreement”).The remainder of our carry was expended during the first and second quarters of 2014, at which point we began accruing and fundingour share of previously carried drilling and completion costs. Please refer to Note 12 - Acquisition and Development Agreement in PartII, Item 8 for additional discussion. Production in 2014 increased 30 percent from the 30.9 MMBOE produced in 2013.Rocky Mountain Region. Operations in our Rocky Mountain region are managed from our office in Billings, Montana. Our2014 activity in this region focused on the development and growth through acquisition of assets targeting the Bakken/Three Forksformations, primarily in Williams, McKenzie, and Divide Counties of North Dakota, and on the expansion and delineation of ourPowder River Basin program in Wyoming. In the Williston Basin, we have approximately 245,000 net acres, of which approximately160,000 net acres are being actively developed in the Bakken and Three Forks formations. In the Powder River Basin, we haveapproximately 175,000 net acres, a large portion of which are prospective for the Frontier and Shannon intervals.Costs incurred in our Rocky Mountain region increased from $474.7 million in 2013 to $1.2 billion in 2014, largely as a resultof our Williston Basin and Powder River Basin proved and unproved property acquisitions totaling $561.6 million in 2014. Thisamount includes the fair value of properties acquired in an asset exchange and the estimated asset retirement obligations associated withthe acquired producing properties. Estimated proved reserves for the region at the end of 2014 increased 43 percent from 76.0 MMBOEat year-end 2013. During the year, we added approximately 25.3 MMBOE of proved reserves in this region through drilling activitiesand approximately 21.9 MMBOE through acquisitions. Production for 2014 increased 18 percent from 7.4 MMBOE produced in 2013.Permian Region. Operations in our Permian region are managed from our office in Midland, Texas. Our Permian region coverswestern Texas and southeastern New Mexico. Our 2014 activity focused on the testing of shale potential and development of our assetsin the Midland Basin. As of December 31, 2014, we had approximately 113,000 net acres in our Permian region.Costs incurred in our Permian region decreased to $195.4 million in 2014 compared to $275.7 million in 2013. Estimatedproved reserves increased 22 percent from 2013 year-end proved reserves of 16.3 MMBOE. Production increased 16 percent from 2.4MMBOE produced in 2013.Mid-Continent Region. Our Mid-Continent region is managed from our office in Tulsa, Oklahoma, and consists of ourHaynesville and Woodford Shale assets.Costs incurred in our Mid-Continent region decreased to $58.9 million in 2014 compared to $91.9 million incurred in 2013.Estimated proved reserves decreased two percent from 2013 year-end proved reserves of 25.2 MMBOE. Production decreased 55percent from 7.7 MMBOE produced in 2013, primarily as a result of the divestiture of our Anadarko Basin assets in December 2013.Subsequent to December 31, 2014, we announced plans to close our regional office in Tulsa, Oklahoma and market ourremaining assets located in the Arkoma Basin of Oklahoma and Arklatex area of east Texas and northern Louisiana.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, 2014. 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 $94.99 per Bbl for oil, $4.35 per MMBtu for natural gas, and $39.91 per Bbl for NGLs for the year ended December 31, 2014.We then adjust these prices to reflect appropriate basis, quality, and location differentials over the period in estimating our provedreserves.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 terms in the Glossary of Oil andGas Terms section of this report for information describing how our reserve replacement metrics are calculated. Our reservereplacement percentages are calculated using information from the Oil and Gas Reserve Quantities section of Supplemental Oil andGas Information located in Part II, Item 8 of this report. We believe the concept of reserve replacement, as well as reserve metricspresented in this report, are widely understood by those who make investment decisions related to the oil and gas exploration andproduction business.8The following table summarizes estimated proved reserves, PV-10, standardized measure of discounted future cash flows, andreserve replacement as of December 31, 2014, 2013, and 2012: As of December 31, 2014 2013 2012Reserve data: Proved developed Oil (MMBbl)89.3 70.2 58.8 Gas (Bcf)784.6 569.2 483.2 NGLs (MMBbl)66.7 43.8 27.2 MMBOE (1)286.8 208.9 166.5Proved undeveloped Oil (MMBbl)80.4 56.3 33.5 Gas (Bcf)682.0 620.1 350.2 NGLs (MMBbl)66.8 60.2 35.1 MMBOE (1)260.9 219.9 126.9Total Proved (1) Oil (MMBbl) (1)169.7 126.6 92.2 Gas (Bcf) (1)1,466.5 1,189.3 833.4 NGLs (MMBbl) (1)133.5 103.9 62.3 MMBOE (1)547.7 428.7 293.4Proved developed reserves %52% 49% 57%Proved undeveloped reserves %48% 51% 43% Reserve data (in millions): Proved developed PV-10$5,253.0 $3,898.6 $2,982.6Proved undeveloped PV-102,363.9 1,629.9 866.5Total proved PV-10$7,616.9 $5,528.5 $3,849.1Standardized measure of discounted future cashflows$5,698.8 $4,009.4 $3,021.0 Reserve replacement – drilling, excluding revisions261% 405% 411%All in – including sales of reserves316% 380% 329%All in – excluding sales of reserves320% 418% 337%Reserve life (years)9.9 8.9 8.0(1) Totals may not sum or recalculate due to rounding. 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, 2014 2013 2012 (in millions)Standardized measure of discounted future net cashflows$5,698.8 $4,009.4 $3,021.0Add: 10 percent annual discount, net of income taxes3,407.2 2,500.6 1,742.1Add: future undiscounted income taxes3,511.4 2,722.2 1,609.4Undiscounted future net cash flows12,617.4 9,232.2 6,372.5Less: 10 percent annual discount without tax effect(5,000.5) (3,703.7) (2,523.4)PV-10$7,616.9 $5,528.5 $3,849.1Proved 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, 2014, we had one undrilled proved undevelopedlocation on our operated Eagle Ford asset that had been on our books in excess of five years. Drilling has been initiated on that locationas of the date of this report. For locations that are more than one location removed from developed producing locations, we utilized reliable geologic andengineering technology to add approximately 61.9 MMBOE of proved undeveloped reserves in the more developed portions of ourEagle Ford shale position and 5.6 MMBOE of proved undeveloped reserves in the more developed portions of our Bakken/Three Forksshale position. 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, 2014, we had 260.9 MMBOE of proved undeveloped reserves, which is an increase of 41.0 MMBOE, or19 percent, from 219.9 MMBOE at December 31, 2013. The following table provides a reconciliation of our proved undevelopedreserves for the year ended December 31, 2014: Total(MMBOE)Total proved undeveloped reserves: Beginning of year219.9Revisions of previous estimates (1)6.6Additions from discoveries, extensions, and infill (2)113.0Sales of reserves—Purchases of minerals in place13.9Removed for five-year rule (4.3)Conversions to proved developed (3)(88.2)End of year260.9____________________________________________(1)Revisions of previous estimates primarily relate to a positive performance revision of 6.1 MMBOE on our operated Eagle Ford assets due to improvedperformance and lower operating expenses.(2)We added 85.0 MMBOE of infill proved undeveloped reserves primarily in our assets in the Bakken/Three Forks and Eagle Ford shale plays, as well asan additional 28.0 MMBOE of proved undeveloped reserves through extensions and discoveries, primarily in our Eagle Ford shale play.(3)Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks plays. During2014, we incurred a total of $908.6 million on projects associated with reserves booked as proved undeveloped reserves at the end of 2013. Please referto Note 12 - Acquisition and Development Agreement in Part II, Item 8 of this report for discussion of the carry of certain drilling and completion costs inour outside-operated Eagle Ford program during the first and second quarters of 2014.As of December 31, 2014, estimated future development costs relating to our proved undeveloped reserves are approximately$746 million, $921 million, and $840 million in 2015, 2016, and 2017, 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 Senior Manager of Reserves, subject to the oversight of ourmanagement and the Audit Committee of our Board of Directors, as discussed below. Our Senior Manager of Reserves has over 15years of experience in the energy industry, and holds a Bachelor of Science degree in Chemical Engineering with a PetroleumCertificate from the University of Alabama. She is also a member of the Society of Petroleum Engineers. Technical, geological, andengineering reviews of our assets are performed throughout the year by our regional staff. This data, in conjunction with economic dataand our ownership information, is used in making a determination of estimated proved reserve quantities. Our regional engineeringtechnical staff do not report directly to our Senior Manager of Reserves; they report to either their respective regional technicalmanagers or directly to the regional manager. This design is intended to promote objective and independent analysis within our regionsin the proved 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 are11required to be within 10 percent of our proved reserve amounts for the total company, as well as for each respective region. RyderScott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting servicesthroughout the world for over 70 years. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit isan Advising Senior Vice President who received a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensedProfessional Engineer in the State of Texas, a member of the Society of Petroleum Engineers, and the Society of Petroleum EvaluationEngineers. The Ryder Scott 2014 report concerning our reserves 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.ProductionThe 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, 2014 2013 2012Net production Oil (MMBbl)16.7 13.9 10.4Gas (Bcf)152.9 149.3 120.0NGLs (MMBbl)13.0 9.5 6.1MMBOE (2)55.1 48.3 36.5Eagle Ford net production(1) Oil (MMBbl)6.9 5.1 3.1Gas (Bcf)120.6 97.1 58.1NGLs (MMBbl)12.7 9.2 5.7MMBOE(2)39.7 30.5 18.5Realized price Oil (per Bbl)$80.97 $91.19 $85.45Gas (per Mcf)$4.58 $3.93 $2.98NGLs (per Bbl)$33.34 $35.95 $37.61Per BOE$45.01 $45.50 $40.39Production costs per BOE Lease operating expense, excluding ad valorem taxes$4.28 $4.49 $4.54Ad valorem taxes$0.46 $0.33 $0.39Transportation costs$6.11 $5.34 $3.81Production taxes$2.13 $2.19 $2.00____________________________________________(1)In each of the years 2014, 2013, and 2012, 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 recalculate due to rounding.12Productive WellsAs of December 31, 2014, we had working interests in 1,500 gross (869 net) productive oil wells and 2,648 gross (931 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 produced when it first commenced production;such designation may not be indicative of current production.Drilling and Completion ActivityAll of our drilling and completion activities are conducted using 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 2014, 2013, and 2012, 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, 2014 2013 2012 Gross Net Gross Net Gross NetDevelopment wells: Oil133 66.1 154 75.4 127 47.2Gas476 165.5 443 162.5 337 124.5Non-productive8 5.3 10 8.5 10 6.3 617 236.9 607 246.4 474 178.0Exploratory wells: Oil5 3.0 6 5.1 9 6.9Gas7 4.8 4 2.4 8 6.8Non-productive4 3.3 1 0.3 8 6.8 16 11.1 11 7.8 25 20.5Total633 248.0 618 254.2 499 198.5A 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.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 2014 (included in the table above), as of February 18, 2015, we wereparticipating in the drilling of 22 gross wells. We operate 15 of these wells on a gross basis (14 on a net basis) and other companiesoperate the remaining 7 gross wells (1 on a net basis). With respect to completion activity, at such date, there were 326 gross wells inwhich we have an interest that were being completed. We operate 87 of these completion activities on a gross basis (78 on a net basis),and were participating in 239 gross (40 on a net basis) outside-operated completion activities. 13AcreageThe following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, andmineral servitudes held by us as of December 31, 2014. Undeveloped acreage includes leasehold interests containing provedundeveloped reserves. Developed Acres (1) Undeveloped Acres (2) Total Gross Net Gross Net Gross NetLouisiana51,079 19,319 33,766 30,858 84,845 50,177Montana50,479 32,654 268,334 184,941 318,813 217,595North Dakota313,809 159,199 159,782 68,675 473,591 227,874Oklahoma46,121 26,330 40,411 19,694 86,532 46,024Texas304,710 166,078 618,047 421,244 922,757 587,322Wyoming59,366 36,499 383,906 303,346 443,272 339,845Other (3)22,637 17,049 40,707 34,981 63,344 52,030Total (4)(5)848,201 457,128 1,544,953 1,063,739 2,393,154 1,520,867____________________________________________(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)Includes interests in Arkansas, Colorado, Kansas, Mississippi, Nebraska, New Mexico, Pennsylvania, Utah, and insignificant other fee and mineralservitude properties.(4)As of the filing date of this report, we had 165,995, 185,174, and 81,249 net acres scheduled to expire by December 31, 2015, 2016, and 2017,respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.(5)Subsequent to December 31, 2014, we announced plans to exit the Mid-Continent region and sell approximately 113,000 net acres in the Arkoma Basinof Oklahoma and Arklatex area of east Texas and northern Louisiana in 2015.Delivery CommitmentsAs of December 31, 2014, we had gathering, processing, and transportation through-put commitments with various parties thatrequire us to deliver fixed, determinable quantities of production over specified time frames. We have an aggregate minimumcommitment to deliver 1,411 Bcf of natural gas and 48 MMBbl of oil. These contracts expire at various dates through 2028. We arerequired to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in theminimum volume commitment for natural gas is projected, we have rights under certain contracts to arrange for third party gas to bedelivered, and such volume will count toward our minimum volume commitment. Our current production is insufficient to offset theseaggregate contractual liabilities, but we expect to fulfill the delivery commitments with production from the future development of ourproved undeveloped reserves and from the future development of resources not yet characterized as proved reserves or througharranging for the delivery of third party gas. Therefore, we do not expect any material shortfalls.14Major 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 2014, we had one major customer that accounted for approximately 19 percent of our total production revenue, which isdiscussed in the next paragraph. In 2014, we also sold to four entities that are under common ownership. In aggregate, these fourentities accounted for approximately 14 percent of our total production revenue in 2014; however, none of these entities individuallyaccounted for greater than 10 percent of our production revenues. During 2013, we had three major customers that accounted forapproximately 26 percent, 16 percent, and 12 percent, respectively, of our total production revenue. During 2012, we had two majorcustomers that accounted for approximately 21 percent and 13 percent, respectively, of our total production 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 through-put commitments for up to 10 years pursuant to each contract.While our joint venture partner is the first purchaser under these contracts, accounting for 19 percent of our total production revenue in2014, we also share with it the risk of non-performance by its counterparty purchasers and have included this joint venture partner as amajor customer in the discussion above. Several of the joint venture partner’s counterparty purchasers under these contracts are alsodirect purchasers of our production.Employees and Office SpaceAs of February 18, 2015, we had 896 full-time employees. None of our employees are subject to a collective bargainingagreement, and we consider our 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, 2014,including our corporate headquarters and regional offices:Region Approximate SquareFootage LeasedCorporate 101,000South Texas & Gulf Coast 64,000Rocky Mountain 50,000Permian 54,000Mid-Continent 54,000Total Leased Office Space 323,000In addition to the leased office space in the table above, we own a total of 44,000 square feet of office space across all four ofour operating regions.Subsequent to year end 2014, we announced plans to close our Tulsa, Oklahoma regional office in 2015.15Title 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 place increased demand on storage volumes. Demand for oil and heatingoil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by globalsupply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Recently, the impact of seasonalityon oil has been somewhat muted by overall supply and demand economics attributable to worldwide production capacity in excess ofexisting worldwide demand for oil. Certain of our drilling, completion, and other operations are also subject to seasonal limitations.Seasonal weather conditions, government regulations and lease stipulations adversely affect our ability to conduct drilling activities insome of the areas where we operate. See Risk Factors - Risks Related to Our Business below for additional discussion.CompetitionThe 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, and/or other policies, legislation, andregulations.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 of increasing 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, imposebonding requirements in order to drill or operate wells, and govern the timing of drilling and location of wells, the method of drillingand casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment ofwells. 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, and16may impose certain requirements regarding the ratability or fair apportionment 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 bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations onfederal leases.In May 2010, the BLM adopted changes to its oil and gas leasing program requiring, among other things, a more detailedenvironmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasingand development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcelreview process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leasesadministered by the BLM.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.17Environmental, 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 requirements to close pits andplug abandoned 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 thefederal Environmental Protection Agency (the “EPA”), individual states administer some or all of the provisions of RCRA, sometimes inconjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated withthe exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous wasteprovisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardouscould be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose ofwastes, 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 to be responsible for the release of a hazardous substance into theenvironment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arrangedfor the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liabilityfor the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resourcesand for the costs of certain health studies. In addition, it is not uncommon for third parties to file claims for personal injury and propertydamage allegedly caused by the hazardous substances released into the environment.18We 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.Endangered 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 production19activities could impair our ability to timely complete well drilling and development and could adversely affect our future productionfrom 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.If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly forus 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, our fracturing activities could become subject toadditional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions onhydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.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 will not have a material adverse impact on our financialcondition and results of operations, we cannot give any assurance that we will not be 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 training20for our employees. Reducing air emissions as a result of leaks, venting or flaring of natural gas during operations has become a majorfocus area for regulatory efforts and for our compliance efforts. While flaring is sometimes necessary, releases of natural gas to theenvironment and flaring is an economic waste and reducing these volumes is a priority for us. To avoid flaring where possible, werestrict testing periods and make every effort to ensure that our production is connected to gas pipeline infrastructure as quickly aspossible after well completions. During 2013 and 2014, we also cooperated with other producers in North Dakota in the ongoingdevelopment 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. All statements, other than statements of 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 address plans and objectives ofmanagement 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 to identify forward-looking statements.Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as:•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capitalexpenditures;•the drilling of wells and other exploration and development activities and plans, as well as possible future 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;•our outlook on future oil, gas, and NGL prices, well costs, and service costs;•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; and•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 different21from any future results or performance expressed or implied by the forward-looking statements. Some of these risks are described in theRisk Factors section of this Form 10-K, and include such factors as:•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;•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;22•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;•the possibility we may face unforeseen difficulties or expenses related to our implementation of a new enterprise resourceplanning software system (“ERP”); 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’s corporate governance section our Corporate GovernanceGuidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics, and the Charters of the Audit,Compensation, Executive, and Nominating and Corporate Governance Committees of our Board of Directors. Information on ourwebsite is not incorporated by reference into this report and should not be considered part of this document.23Glossary 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 be24incurred 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. The calculations of various finding and development cost metrics are explained below.Finding and development cost – Drilling, excluding revisions. Calculated by dividing the amount of costs incurred for development andexploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, and infill drilling, duringthe same period.Finding and development cost – Drilling, including revisions. Calculated by dividing the amount of costs incurred for development andexploration activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, andrevisions of previous estimates, during the same period.Finding and development cost – Drilling and acquisitions, excluding revisions. Calculated by dividing the amount of costs incurred fordevelopment, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added throughdiscoveries, extensions, infill drilling, and acquisitions, during the same period.Finding and development cost – Drilling and acquisitions, including revisions. Calculated by dividing the amount of costs incurred fordevelopment, exploration, and acquisition of proved properties, by the amount of estimated net proved reserves added throughdiscoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates, during the same period.Finding and development cost – All in, including sales of reserves. Calculated by dividing the amount of total capital expenditures foroil and natural gas activities, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling,acquisitions, and revisions of previous estimates less sales of reserves, during the same period.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.MCFE. One thousand cubic feet of natural gas equivalent. Natural gas equivalents are determined using the ratio of six Mcf of naturalgas to one Bbl of oil or NGLs.MMBbl. One million barrels of oil, NGLs, or other liquid hydrocarbons.25MMBOE. 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 and administrative expenses, debt service, future income tax expenses, or depreciation,depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect ofincome taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide anindicative representation of the relative value of 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.26Reserve 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. The calculations of variousreserve replacement metrics are explained below.Reserve replacement – Drilling, excluding revisions. Calculated as a numerator comprised of the sum of reserve extensions anddiscoveries and infill reserves in an existing proved field divided by production for the same period. This metric is an indicator of therelative success a company is having in replacing its production through drilling activity.Reserve replacement – Drilling, including revisions. Calculated as a numerator comprised of the sum of reserve extensions, discoveries,infill reserves, and revisions of previous estimates in an existing proved field divided by production for the same period. This metric isan indicator of the relative success a company is having in replacing its production through drilling activity with an adjustment forrevisions.Reserve replacement – Drilling and acquisitions, excluding revisions. Calculated as a numerator comprised of the sum of reserveacquisitions and reserve extensions, discoveries, and infill reserves in an existing proved field divided by production for the sameperiod. This metric is an indicator of the relative success a company is having in replacing its production through drilling andacquisition activities.Reserve replacement – Drilling and acquisitions, including revisions. Calculated as a numerator comprised of the sum of reserveacquisitions and reserve extensions, discoveries, infill reserves, and revisions of previous estimates in an existing proved field dividedby production for the same period. This metric is an indicator of the relative success a company is having in replacing its productionthrough drilling and acquisition activities with an adjustment for revisions.Reserve replacement – All in, excluding sales of reserves. The sum of reserve extensions and discoveries, infill drilling, reserveacquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for the same period.Reserve replacement –All in, including sales of reserves. The sum of sales of reserves, infill drilling, reserve extensions and discoveries,reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that sameperiod.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.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 price 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;•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.29These 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.In 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 future30abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantitiesof proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospectiveacquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject propertieswill 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 decrease or if we encounter operatingdifficulties that result in our cash flows from operations being less than expected, we may reduce our planned capital expendituresunless we can raise additional funds through debt or equity financing or the divestment of assets. Debt or equity financing may notalways be available to us in sufficient amounts or on acceptable terms, and the proceeds offered to us for potential divestitures may notalways be of acceptable value to us.If our revenues decrease due to lower crude oil, natural gas, or NGL prices, decreased production, or other reasons, and if wecannot obtain funding through our credit facility, other acceptable debt or equity financing arrangements, or through the sale of assets,our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatlylimited.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. Over the last few years, the need for talented people across all disciplines in the industry has grown, while the number oftalented people available has not grown at the same pace, and in many cases, is declining due31to the demographics of the industry. Our inability to compete effectively with companies in any area of our business could have amaterial adverse impact on our business 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 the services of these or other key personnel could adversely affect our business. Our drilling success and thesuccess of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists,engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technicalpersonnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.The 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, 2014, 48 percent, or 260.9 MMBOE, of our estimated proved reserves were proved undeveloped, and threepercent, or 17.2 MMBOE, were proved developed non-producing. In order to develop our proved undeveloped reserves, as ofDecember 31, 2014, we estimate approximately $3.1 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, 2014, we estimate capital expenditures ofapproximately $29 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.32You 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 31,2014, was estimated using a calculated 12-month average sales price of $4.35 per MMBtu of natural gas (NYMEX Henry Hub spotprice), $94.99 per Bbl of oil (NYMEX WTI spot price), and $39.91 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 2014, our monthlyaverage realized natural gas prices, excluding the effect of derivative settlements, were as high as $5.78 per Mcf and as low as $3.69per Mcf. For the same period, our monthly average realized crude oil prices before the effect of derivative settlements were as high as$94.36 per Bbl and as low as $50.22 per Bbl, and were as high as $42.83 per Bbl and as low as $19.94 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;•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.33Integrating 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.We 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. The failure of a third-party service provider to adequately perform operations could delay drilling orcompletion or reduce production from the property and adversely affect our financial 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 available for oil and gas properties.As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examiningrecords in the appropriate governmental offices and title abstract facilities before attempting to acquire or place under lease a specificmineral 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.34Exploration 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;•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.35Results in our newer resource plays may be more uncertain than results in resource plays that are more developed and havelonger established production histories. For example, industry experience and knowledge in the Eagle Ford shale play, is more limitedcompared to more established resource plays, such as the Barnett or Woodford shales, and we and the industry generally have lessinformation with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than otherareas with longer histories of development and production. Drilling and completion techniques that have proven to be successful inother resource plays are being used in the early development of these new plays; however, we can provide no assurance of the ultimatesuccess 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.Our 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 would lose our right to develop the related properties. Our total net acreageexpiring in the next three years represents approximately 41 percent of our total net undeveloped acreage at December 31, 2014.Although we have identified numerous potential drilling locations, we may not be able to economically produce crude oil, natural gas,or NGLs from all of them and our actual drilling activities may materially differ from those presently identified, which could adverselyaffect 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.36Uncertainties 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, if 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 towards the new wellbore (and potentially away from existing wellbores). As a result, thedrilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to furtherdevelop our 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 swap andcollar arrangements for crude oil, natural gas, and NGLs. As of December 31, 2014, we were in a net accrued asset position of $592.1million with respect to our crude oil, natural gas, and NGL derivative activities. These activities may expose us to the risk of financialloss in certain 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 the recent decline 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.37In 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 recent decrease in crudeoil prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices ofcommodities we sell. The Company does not believe the loss of any single purchaser would materially impact its operating results, asthe Company has numerous options for purchasers in each of its operating regions for its crude oil, natural gas, and NGL production.Please refer to Note 1 - Summary of Significant Accounting Policies, under the heading Concentration of Credit Risk and MajorCustomers in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers.We have entered into firm transportation contracts that require us to pay fixed amounts 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 and liquidity could be adversely affected.As of December 31, 2014, we were contractually committed to deliver 1,411 Bcf of natural gas and 48 MMBbl of crude oilpursuant to contracts expiring at various dates through 2028. We may enter into additional firm transportation agreements as ourdevelopment of our resource plays expands. At the current time, we do not have enough proved developed reserves to offset thesecontractual liabilities, but we intend to develop reserves that will exceed the commitments and therefore do not expect any materialshortfalls. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions ofoperations, or delays in connecting new volumes to gathering systems or pipelines for an extended period of time, the requirements topay for quantities not delivered could have a material impact on our results of operations 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 and impairment of unproved propertiestotaling $84.5 million and $75.6 million, respectively, during 2014, $172.6 million and $46.1 million, respectively, during 2013, and$208.9 million and $16.3 million, respectively, during 2012. Commodity prices significantly declined in 2014. Continued declines inthe prices of crude oil, natural gas, or NGLs or unsuccessful exploration efforts could cause additional proved and/or unprovedproperty impairments in the future.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.38Lower 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 crude oil and natural gas properties, which in turn is impactedby crude oil, natural gas, and NGL prices. The current borrowing base under our credit facility is $2.4 billion. The prices of crude oiland NGLs declined significantly beginning in mid-2014 and declined further subsequent to December 31, 2014. These declines in theprices of crude oil and NGLs, or significant declines in natural gas prices in the future could limit our borrowing base and reduce theamount we can borrow under our credit facility. Our amendment to our credit facility in 2014 specified that the borrowing base was notreduced by the issuance of the 6.125% Senior Notes due 2022 (“2022 Notes”) that we issued on November 17, 2014, and will remainat $2.4 billion until the next scheduled redetermination date of April 1, 2015. Additionally, divestitures of properties or other bondofferings 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, 2014, we had $350.0 million of long-term senior unsecured debt outstanding relating to our 6.625% SeniorNotes due 2019 (the “2019 Notes”) that we issued on February 7, 2011; $350.0 million of long-term senior unsecured debt outstandingrelating to our 6.50% Senior Notes due 2021 (the “2021 Notes”) that we issued on November 8, 2011; $600.0 million of long-termsenior unsecured debt outstanding relating to our 2022 Notes that we issued on November 17, 2014; $400.0 million of long-term seniorunsecured debt outstanding relating to our 6.50% Senior Notes due 2023 (the “2023 Notes”) that we issued on June 29, 2012; and$500.0 million of long-term senior unsecured debt outstanding relating to our 5.0% Senior Notes due 2024 (the “2024 Notes”) that weissued on May 20, 2013 (collectively, the 2019 Notes, the 2021 Notes, the 2022 Notes, the 2023 Notes, and the 2024 Notes are referredto as our “Senior Notes”); and $166.0 million of outstanding borrowings under our secured credit facility. We had three outstandingletters of credit in the aggregate amount of $808,000 (which reduce the amount available for borrowing under the facility on a dollar-for-dollar basis), resulting in $1.3 billion of available debt capacity under our credit facility, assuming the borrowing conditions underthis facility will be met. Our long-term debt represented 51 percent of our total book capitalization as of December 31, 2014.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; and•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 are39unable to service our debt, due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capitalexpenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sellour 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 orfuture debt agreements, including our existing and future credit agreements, may prohibit us from pursuing any of these alternatives.Further, changes in the credit ratings of our debt may negatively affect the cost, terms, conditions, and availability 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;•create liens that secure debt;•enter into transactions with affiliates; and•merge or consolidate with another company.40Our 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 away from 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 allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into theenvironment. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminatefunds available for exploration, development, or acquisitions, or cause us to incur losses.We 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 substantial41assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered byinsurance, 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, could result in material costs or claims with respect to properties we own or have owned.We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations betweenstate and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, includingjoint and several, strict liability under federal, state, and tribal environmental laws for noise emissions and for discharges of crude oil,natural gas, and associated liquids or other pollutants into the air, soil, surface water, or groundwater. We could be required to spendsubstantial amounts on investigations, litigation, and remediation for these emissions and discharges and other compliance issues. Anyunpermitted 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.Seasonal 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 periodic42shortages. Wildlife seasonal restrictions may limit access to federal leases or across federal lands. Possible restrictions may includeseasonal restrictions in greater sage-grouse habitat during breeding and nesting seasons, within a certain distance of active raptor nestsduring fledging, and in big game winter or parturition ranges during winter or calving seasons. These constraints and the resultingshortages 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 an essential and common practice in the oil and gas industry used to stimulate production of oil, naturalgas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil andnatural gas properties, including our unconventional resource plays in the Eagle Ford shale of south Texas and the Bakken/Three Forksformations in North Dakota. Hydraulic fracturing involves using water, sand and certain chemicals to fracture the hydrocarbon-bearingrock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gascommissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulicfracturing activities as outlined below.The EPA has authority to regulate underground injections that contain diesel in the fluid system under the SDWA. The EPA haspublished an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority.The EPA also plans to update its chloride water quality criteria for the protection of aquatic life under the Clean Water Act. Flowbackand produced water from the hydraulic fracturing process contain total dissolved solids, including chlorides, and regulation of thesefluids could be affected by the new criteria. The EPA has delayed issuing a draft criteria document until 2015. The EPA has alsoannounced that it will develop pre-treatment standards for disposal of wastewater produced from shale gas operations through publiclyowned treatment works. The regulations will be developed under the EPA’s Effluent Guidelines Program under the authority of theClean Water Act. The EPA anticipates issuing the proposed rules in 2015. If the EPA implements further regulations of hydraulicfracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays orcurtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/orcompleting 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. For example, Texas adopted a law in June 2011requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components and volumeof water used in the hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, mayrestrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, several municipalities havepassed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage forchallenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townshipsacross the United States. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting,or in the future plan to conduct, operations, 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.Several agencies of the federal governmental are actively involved in studies or reviews that focus on environmental aspectsand impacts of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulicfracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulicfracturing practices and government studies related thereto. Furthermore, a number of federal agencies are analyzing, or have beenrequested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of thepotential43environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report in 2012, and plansto issue a draft report of results in 2015 for public comment, following release of peer reviewed papers in late 2014 and early 2015. TheUnited States Department of Energy is actively involved in research on hydraulic fracturing practices, including groundwaterprotection. Also, the United States Department of the Interior proposed a rule to regulate hydraulic fracturing on public lands in May of2013. The proposed rule contains disclosure requirements and other mandates for well integrity and management of water produced bythe process, and is under review by the Office of Management and Budget.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 is 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 of hazardous air pollutants not currently subject to MACT standards.These rules will require additional control equipment, changes to procedure, and extensive monitoring and reporting. The EPA stated inJanuary 2013, however, that it intends to reconsider portions of the final rule. On September 23, 2013, the EPA published newstandards for storage tanks subject to the NSPS. In December 2014, the EPA finalized additional updates to the 2012 NSPS. Theamendments clarified stages for flowback and the point at which green completion equipment is required and updated requirements forstorage tanks and leak detection requirements for processing plants. The EPA has stated that it continues to review other issues raised inpetitions for reconsideration. We are currently evaluating the effect of these rules on our business.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 could spur future litigation and bring increased attention to the practice ofhydraulic fracturing. Judicial decisions could also lead to44increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead tooperational delays or restrictions or increased costs in the exploration for and production of oil, natural gas, and associated liquids,including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption ofadditional federal, state, or local laws, or the implementation of new regulations, regarding hydraulic fracturing could potentially causea decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect ourfinancial position, results of operations, 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.Our 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 to45warming of the earth’s atmosphere and other climatic changes. Based on this finding, the EPA has over the past four years adopted andimplemented a comprehensive suite of regulations to restrict and otherwise regulate emissions of greenhouse gases under existingprovisions of the CAA. In particular, the EPA has adopted two sets of rules regulating greenhouse gas emissions under the CAA. Onerule requires a reduction in greenhouse gas emissions from motor vehicles, and the other regulates permitting and greenhouse gasemissions from certain large stationary sources. These EPA regulatory actions have been challenged by various industry groups,initially in the D.C. Circuit, which in 2012 ruled in favor of the EPA in all respects. However, in June 2014, the United States SupremeCourt reversed the D.C. Circuit and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement toobtain a permit based solely on emissions of greenhouse gases. However, large sources of air pollutants other than greenhouse gaseswould still be required to implement the best available capture technology for greenhouse gases. The EPA has also adopted reportingrules for greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineriesas well as certain onshore oil and natural gas extraction 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. There is a continuing risk of claims being filed againstcompanies that have significant greenhouse gas emissions, and new claims for damages and increased government scrutiny will likelycontinue. Such cases often seek to challenge air emissions permits that greenhouse gas emitters apply for, seek to force emitters toreduce their emissions, or seek damages for alleged climate change impacts to the environment, people, and property. Any courtrulings, laws or regulations that restrict or require reduced emissions of greenhouse gases could lead to increased operating andcompliance costs, and could have an adverse effect on demand for the oil and natural gas that 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. The EPAplans to propose the rule in 2015 and finalize the standards in 2016. The focus on legislating methane also could eventually 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;46•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, application of agencies’ existing regulations for source categorieswith high methane emissions, and determinations of whether a source qualifies 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.Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments toreduce the effect of commodity price, interest rate and other risks associated with our business.The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was signed into law on July21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entitiesthat participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and tradeexecution requirements. On October 18, 2011, the Commodities Futures Trading Commission (the “CFTC”) approved regulations to setposition limits for certain futures and option contracts in the major energy markets, which were successfully challenged in federaldistrict court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association andlargely vacated by the court. On November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain corefutures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedgingtransactions. The comment period on these new rules has been reopened multiple times since comments were first due in early January2014, and as these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from themandatory swap clearing requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivativeactivities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also requirethe counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be ascreditworthy as the current counterparties. Therefore, the Dodd-Frank Act and the rules promulgated thereunder could significantlyincrease the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivativecontracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure ourexisting derivative contracts, and increase our exposure to less creditworthy counterparties.47If we reduce our use of derivatives as a result of the Dodd-Frank Act and related regulations, our results of operations maybecome more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capitalexpenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislatorsattributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore beadversely affected if a consequence of the Dodd-Frank Act and related regulations is to lower commodity prices. Any of theseconsequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.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 substantial costsin order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised orreinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs we pay for suchservices. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a materialadverse effect on our business, financial condition and results of operations.A 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.48New 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.We implemented a new ERP system beginning January 1, 2015. We may experience unforeseen difficulties or delays related toimplementation of the new system.We implemented a new ERP system beginning January 1, 2015. We rigorously planned and tested the implementation of thissystem prior to its implementation; however, if we encounter unforeseen difficulties in the use of this system, we may experience delaysin financial reporting, weaknesses in internal controls, or unanticipated expenses.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 lead tofinancial 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.49Risks Related to Our Common StockThe price of our common stock may fluctuate significantly, which may result in losses for investors.From January 1, 2014, to February 18, 2015, the low and high intraday sales price per share of our common stock as reportedby the New York Stock Exchange ranged from a low of $29.41 per share in December 2014 to a high of $90.38 per share in September2014. 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 18, 2015, 67,407,214 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 512,987 shares of our common stock and 744,253 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 18, 2015, there were67,463,060 shares of our common stock outstanding.50We 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 Securities ExchangeAct of 1934.ITEM 3. LEGAL PROCEEDINGSFrom time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course ofbusiness. As of the filing date of this report, no legal proceedings are pending against us that we believe individually or collectivelycould 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.51PART 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 2014 and2013, as reported by the New York Stock Exchange:Quarter Ended High LowDecember 31, 2014 $79.89 $29.41September 30, 2014 $90.38 $74.57June 30, 2014 $85.39 $71.00March 31, 2014 $90.22 $69.03 December 31, 2013 $94.00 $76.72September 30, 2013 $77.70 $60.22June 30, 2013 $65.55 $55.30March 31, 2013 $62.26 $52.67PERFORMANCE GRAPHThe following performance graph compares the cumulative return on our common stock, for the period beginningDecember 31, 2009, and ending on December 31, 2014, 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 18, 2015, the number of record holders of our common stock was 78. Based upon inquiry,management believes that the number of beneficial owners of our common stock is approximately 25,100.52Dividends. 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 2005 through 2014. We expect ourpractice of paying dividends on our common stock to continue, although the payment of future dividends will continue to depend onour earnings, cash flow, capital requirements, financial condition, and other factors, including the discretion of our Board of Directors.In addition, the payment of dividends is subject to covenants in our credit facility that limit our annual dividend payment to no morethan $50.0 million per year. We are also subject to certain covenants under our Senior Notes that restrict certain payments, includingdividends; provided, however, the first $6.5 million of dividends paid each year are not restricted by this covenant. Based on ourcurrent performance, we do not anticipate that these covenants will restrict future annual dividend payments of $0.10 per share ofcommon stock. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $6.7 million for each year endedDecember 31, 2014, and December 31, 2013.Restricted Shares. We have no restricted shares outstanding as of December 31, 2014, 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, 2014, 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) Average PricePaid per Share Total Number of SharesPurchased as Part ofPublicly AnnouncedProgram Maximum Number ofShares that May Yetbe Purchased Underthe Program(2)January 1, 2014 -March 31, 2014— $— — 3,072,184April 1, 2014 -June 30, 2014866 $73.59 — 3,072,184July 1, 2014 -September 30, 2014124,942 $84.14 — 3,072,184October 1, 2014 -October 31, 2014668 $71.78 — 3,072,184November 1, 2014 -November 30, 2014— $— — 3,072,184December 1, 2014 -December 31, 2014— $— — 3,072,184Total October 1, 2014 -December 31, 2014668 $71.78 — 3,072,184Total126,476 $84.00 — 3,072,184 ____________________________________________(1)All shares purchased in 2014 were purchased by us to offset tax withholding obligations that occur upon the delivery of outstanding shares underlyingRSUs 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 with53existing 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.54ITEM 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, 2014 2013 2012 2011 2010 (in millions, except per share data)Total operating revenues$2,522.3 $2,293.4 $1,505.1 $1,603.3 $1,092.8Net income (loss)$666.1 $170.9 $(54.2) $215.4 $196.8Net income (loss) per share: Basic$9.91 $2.57 $(0.83) $3.38 $3.13Diluted$9.79 $2.51 $(0.83) $3.19 $3.04Total assets at year-end$6,516.7 $4,705.2 $4,199.5 $3,799.0 $2,744.3Long-term debt: Revolving credit facility$166.0 $— $340.0 $— $48.03.50% Senior Convertible Notes,net of debt discount$— $— $— $285.1 $275.7Senior Notes$2,200.0 $1,600.0 $1,100.0 $700.0 $—Cash dividends declared and paidper common share$0.10 $0.10 $0.10 $0.10 $0.1055Supplemental Selected Financial and Operations Data For the Years Ended December 31, 2014 2013 2012 2011 2010 Balance Sheet Data (in millions) Total working capital (deficit)$(39.6) $8.4 $(201.0) $(42.6) $(227.4)Total stockholders’ equity$2,286.7 $1,606.8 $1,414.5 $1,462.9 $1,218.5Weighted-average common shares outstanding (inthousands) Basic67,230 66,615 65,138 63,755 62,969Diluted68,044 67,998 65,138 67,564 64,689Reserves Oil (MMBbl)169.7 126.6 92.2 71.7 57.4Gas (Bcf)1,466.5 1,189.3 833.4 664.0 640.0 NGLs (MMBbl)133.5 103.9 62.3 27.5 —MMBOE547.7 428.7 293.4 209.9 164.1Production and Operations (in millions) Oil, gas, and NGL production revenue$2,481.5 $2,199.6 $1,473.9 $1,332.4 $836.3Oil, gas, and NGL production expense$715.9 $597.0 $391.9 $290.1 $195.1Depletion, depreciation, amortization, and assetretirement obligation liability accretion$767.5 $822.9 $727.9 $511.1 $336.1General and administrative$167.1 $149.6 $119.8 $118.5 $106.7Production Volumes Oil (MMBbl)16.7 13.9 10.4 8.1 6.4Gas (Bcf)152.9 149.3 120.0 100.3 71.9NGLs (MMBbl)13.0 9.5 6.1 3.5 —MMBOE55.1 48.3 36.5 28.3 18.3Realized price Oil (per Bbl)$80.97 $91.19 $85.45 $88.23 $72.65Gas (per Mcf)$4.58 $3.93 $2.98 $4.32 $5.21NGLs (per Bbl)$33.34 $35.95 $37.61 $53.32 $—Adjusted price (net of derivative settlements) Oil (per Bbl)$82.68 $89.92 $83.52 $78.89 $66.85Gas (per Mcf)$4.40 $4.14 $3.48 $4.80 $6.05NGLs (per Bbl)$34.18 $36.66 $38.90 $47.90 $—Expense per BOE Lease operating expenses$4.74 $4.82 $4.93 $5.30 $6.63Transportation costs$6.11 $5.34 $3.81 $3.05 $1.15Production taxes$2.13 $2.19 $2.00 $1.90 $2.86Depletion, depreciation, amortization, and assetretirement obligation liability accretion$13.92 $17.02 $19.95 $18.07 $18.33General and administrative$3.03 $3.09 $3.28 $4.19 $5.82Statement of Cash Flow Data (in millions) Provided by operating activities$1,456.6 $1,338.5 $922.0 $760.5 $497.1Used in investing activities$(2,478.7) $(1,192.9) $(1,457.3) $(1,264.9) $(361.6)Provided by (used in) financing activities$740.0 $130.7 $422.1 $618.5 $(141.1) 56Note: Beginning in 2011, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transferfor each product. Rapid production growth from our NGL-rich assets associated with plant product sales contracts necessitated a change in our reporting ofproduction volumes. Our 2010 NGL production volumes, revenues, and prices have not been reclassified to conform to the current presentation given theimmateriality of the amounts.57ITEM 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 have leading positions in the Eagle Ford shale and Bakken/Three Forks resource plays that are thefocus of our development programs. We also have smaller delineation and exploration programs in the Powder River Basin, thePermian Basin, and in east Texas. We have built a portfolio of onshore properties primarily through early entry into existing andemerging resource plays. This portfolio is comprised of properties with established production and reserves, prospective drillingopportunities, and unconventional resource prospects. We believe our strategy provides for stable and predictable production andreserves growth.Our strategic objective is to build our ownership and operatorship of North American oil, gas, and NGL producing assets thathave high operating margins and significant opportunities for additional economic investment. We pursue opportunities through bothacquisitions and exploration, and seek to maximize the value of our assets through industry leading technology application andoutstanding operational execution. We are returns focused and maintain a simple, strong balance sheet through a conservative approachto leverage.In 2014, we had the following financial and operational results:•At year-end 2014, we had estimated proved reserves of 547.7 MMBOE, of which 55 percent were liquids (oil and NGLs)and 52 percent were characterized as proved developed. We added 143.9 MMBOE through our drilling program, themajority of which related to our activity in the Eagle Ford shale in south Texas and the Bakken/Three Forks program inNorth Dakota, and acquired 21.9 MMBOE near our existing Gooseneck area in Divide County, North Dakota and in thePowder River Basin in Wyoming. We had upward engineering revisions of 10.4 MMBOE primarily related to improvedperformance and lower operating expenses in our operated Eagle Ford assets. We divested of 2.1 MMBOE of provedreserves in the Montana portion of the Williston Basin. Our proved reserve life increased to 9.9 years in 2014 compared to8.9 years in 2013. Please refer to Reserves included in Part I, Items 1 and 2 of this report for additional discussion.•The PV-10 of our estimated proved reserves was $7.6 billion as of December 31, 2014, compared with $5.5 billion as ofDecember 31, 2013. The after tax amount, represented by the standardized measure calculation, was $5.7 billion as ofDecember 31, 2014, compared with $4.0 billion as of December 31, 2013. The standardized measure calculation ispresented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliationbetween PV-10 and the standardized measure of discounted future net cash flows is shown under Reserves in Part I, Items 1and 2 of this report.•We had record annual production in 2014. Our average daily production in 2014 was 45.6 MBbls of oil, 419.0 MMcf ofgas, and 35.6 MBbls of NGLs, for an average daily equivalent production rate of 151.1 MBOE, compared with 132.4MBOE in 2013, an increase of 14 percent year-over-year. Please refer to the caption Production Results below for additionaldiscussion.58•We recorded net income of $666.1 million, or $9.79 per diluted share, for the year ended December 31, 2014. Thiscompares with net income of $170.9 million, or $2.51 per diluted share, for the year ended December 31, 2013. Thisincrease in net income in 2014 is driven largely by higher production, an increase in the fair value of commodity derivativecontracts, and an increase in oil, gas, and NGL production revenue. Please refer to the caption Comparison of FinancialResults and Trends Between 2014 and 2013 below for additional discussion regarding the components of net income.•We had record cash flow provided by operating activities of $1.5 billion for the year ended December 31, 2014, comparedwith $1.3 billion for the year ended December 31, 2013, which was an increase of nine percent year-over-year. Please referto Analysis of cash flow changes between 2014 and 2013 below for additional discussion.•Costs incurred for oil and gas property acquisitions and exploration and development activities for the year endedDecember 31, 2014, totaled $2.7 billion. The majority of our drilling and completion costs incurred during this period werein our Eagle Ford shale and Bakken/Three Forks programs. We acquired approximately $561.6 million of proved andunproved properties in our Gooseneck area and in the Powder River Basin during 2014. Total costs incurred for the sameperiod in 2013 totaled $1.7 billion. Please refer to the caption Costs Incurred in Oil and Gas Producing Activities below foradditional discussion.•Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2014, was $1.6 billion, comparedwith $1.5 billion for the same period in 2013. Please refer to the caption Non-GAAP Financial Measures below foradditional discussion, including our definition of adjusted EBITDAX and reconciliations of our GAAP net income (loss) andnet cash provided by operating activities to adjusted EBITDAX.Reserve Replacement, Finding and Development Costs, and GrowthAn exploration and production company depletes part of its asset base with each unit of oil, gas, or NGL it produces. Our futuregrowth will depend on our ability to economically add reserves in excess of production. The information used to calculate reservereplacement and finding and development cost metrics is included in the Supplemental Oil and Gas Information section located in PartII, Item 8 of this report with the terms defined in the Glossary of Oil and Gas Terms in Part I, Items 1 and 2 of this report.The following table provides various reserve replacement and finding and development cost metrics for the year endedDecember 31, 2014: Reserve Replacement Percentage Finding and Development Cost perBOE (1) ExcludingDivestitures IncludingDivestitures ExcludingDivestitures IncludingDivestituresDrilling, excluding revisions261% 257% $14.39 $14.60Drilling, including revisions280% 276% $13.41 $13.60Drilling and acquisitions, excluding revisions301% 297% $14.14 $14.32Drilling and acquisitions, including revisions320% 316% $13.30 $13.46Reserve acquisitions40% 36% $12.49 $13.83All-in320% 316% $15.39 $15.58____________________________________________(1) Please refer to Note 12 - Acquisition and Development Agreement in Part II, Item 8 for a discussion of the arrangement under which we were carried on 90percent of certain drilling and completion costs for a portion of 2014. The remaining carry was utilized during the second quarter of 2014.59The following table provides average reserve replacement and finding and development cost metrics for the three-year periodended December 31, 2014: Reserve Replacement Percentage Finding and Development Cost perBOE (1) ExcludingDivestitures IncludingDivestitures ExcludingDivestitures IncludingDivestituresDrilling, excluding revisions350% 333% $10.53 $11.06Drilling, including revisions341% 325% $10.80 $11.35Drilling and acquisitions, excluding revisions366% 350% $10.65 $11.16Drilling and acquisitions, including revisions358% 341% $10.91 $11.44Reserve acquisitions17% N/M $13.16 N/MAll-in358% 341% $12.22 $12.81____________________________________________N/M - Percentage or amount, as applicable, is not meaningful.(1) Please refer to Note 12 - Acquisition and Development Agreement in Part II, Item 8 for a discussion of the arrangement under which we were carried on 90percent of certain drilling and completion costs in 2012, 2013, and for a portion of 2014.Growing net asset value per share is an important factor in growing our stock price over the long term. We believe annualreserve replacement percentages and finding and development costs are important analytical measures and are widely used by investorsand industry peers in evaluating and comparing the performance of oil and gas companies. While single-year measurements aremeaningful, we believe aberrations, causing both positive and negative results, will occur over the short term.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.60The 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, 2014, 2013, and 2012: For the Years Ended December 31, 2014 2013 2012Crude Oil (per Bbl): Average NYMEX price$93.03 $97.99 $94.10Realized price, before the effects of derivative settlements$80.97 $91.19 $85.45Effects of derivative settlements$1.71 $(1.27) $(1.93) Natural Gas: Average NYMEX price (per MMBtu)$4.35 $3.73 $2.75Realized price, before the effects of derivative settlements (per Mcf)$4.58 $3.93 $2.98Effects of derivative settlements (per Mcf)$(0.18) $0.21 $0.50 NGLs (per Bbl): Average OPIS price$38.93 $40.44 $44.91Realized price, before the effects of derivative settlements$33.34 $35.95 $37.61Effects of derivative settlements$0.84 $0.71 $1.29____________________________________________Note: 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 an industry standard composite barrel and does not necessarily represent ouractual product mix for NGL production. Actual prices received for NGLs produced 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 be volatile. In addition to supply and demand fundamentals, as a globalcommodity, the price of oil will continue to be impacted by real or perceived geopolitical risks in oil producing regions of the world,particularly the Middle East. The relative strength of the U.S. dollar compared to other currencies also could affect the price of oil.Lower forecasted levels of global economic growth combined with excess global supply have weighed on oil prices in recent months.This was exacerbated by the decision of the Organization of Petroleum Exporting Countries (“OPEC”) not to cut production inNovember of 2014. The supply of NGLs in the United States has continued to grow as a result of the number of industry participantstargeting projects that produce these products in recent years, negatively impacting prices as demand is not as strong. The prices ofseveral NGL products generally correlate to the price of oil and accordingly prices for these products have fallen in recent months andare likely to continue following that market. Gas prices have been under downward pressure for the past several years due to highlevels of gas in storage. Longer term, we anticipate natural gas prices will trade in a range higher than current price levels. Changes toexisting laws and regulations pertaining to the ability to export oil, gas, and NGLs also have the potential to impact the prices for thesecommodities.61The 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 18, 2015, and December 31, 2014: As of February 18,2015 As of December 31,2014NYMEX WTI oil (per Bbl)$57.14 $56.57NYMEX Henry Hub gas (per MMBtu)$3.05 $3.06OPIS NGLs (per Bbl)$23.80 $20.95Derivative 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 established a base cash flow stream for our future operations and have partially reduced our exposure to volatilityin commodity prices in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of theupward movements in oil and gas prices while also setting a price floor for a portion of our production. Please refer to Note 10 -Derivative Financial Instruments in Part II, Item 8 of this report for additional information regarding our oil, gas, and NGL derivatives.The Dodd-Frank Act included provisions requiring over-the-counter derivative transactions to be cleared throughclearinghouses and traded on exchanges. On July 10, 2012, the Commodity Futures Trading Commission (“CFTC”) and the SECadopted final joint rules under Title VII of the Dodd-Frank Act, which define certain terms that determine what types of transactions willbe subject to regulation under the Dodd-Frank Act swap rules. The issuance of these final rules also triggers compliance dates for anumber of other final Dodd-Frank Act rules, including new rules proposed by the CFTC governing margin requirements for unclearedswaps entered into by non-bank swap entities, and new rules proposed by U.S. banking regulators regarding margin requirements foruncleared swaps entered into by bank swap entities. The ultimate effect on our business of these new rules and any additionalregulations is currently uncertain. Under CFTC rules we believe our derivative activity will qualify for the non-financial, commercialend-user exception, which exempts derivatives intended to hedge or mitigate commercial risk entered into by entities predominantlyengaged in non-financial activity from the mandatory swap clearing requirement. However, we are not certain whether the provisions ofthe final rules and regulations will exempt us from the requirements to post margin in connection with commodity price riskmanagement activities. Final rules and regulations on major provisions of the legislation, such as new margin requirements, are to beestablished through regulatory rulemaking. Although we cannot predict the ultimate outcome of these rulemakings, new rules andregulations in this area may result in increased costs and cash collateral requirements for the types of derivative instruments we use tomanage our financial risks related to volatility in oil, gas, and NGL commodity prices.2014 HighlightsOperational Activities. The primary focus of our operated drilling activity this year was oil and NGL-rich gas projects, with themajority of our 2014 capital budget being deployed to the development of our Eagle Ford shale and Bakken/Three Forks programs.In our operated Eagle Ford shale program in south Texas, we operated between four and five drilling rigs supported by two fracspreads during 2014. In 2014, our development program shifted to utilizing longer laterals and completions with higher sand loadings.Early results from these enhanced completion techniques suggest significantly improved well performance.62In our non-operated Eagle Ford shale program, the operator ran nine to 10 drilling rigs in the first half of 2014, but dropped toseven rigs in the third quarter. During the second quarter of 2014, the remainder of our carry under our Acquisition and DevelopmentAgreement with Mitsui was expended. At that time, we began accruing and funding our full share of drilling and completion costs forthis program.In our Bakken/Three Forks program, we operated three drilling rigs for most of 2014 and added two rigs during the fourthquarter. We focused on infill drilling of our Raven/Bear Den and Gooseneck properties in the North Dakota portion of the WillistonBasin. We are monitoring the results of various tests, including drilling and completion optimizations, down-spacing of both ouroperated and non-operated properties, and we are testing the Bakken interval on our Gooseneck acreage. During 2014, we completedproved and unproved property acquisitions that added approximately 74,000 net acres in our Gooseneck area for a total of $410.1million.In our Permian program, we operated two drilling rigs during 2014 focused on horizontal testing and development of theWolfcamp B interval in our Sweetie Peck property in Upton County, Texas. In our Buffalo prospect in Gaines and Dawson Counties,Texas, we are testing various target intervals, including the Wolfcamp B, Wolfcamp D, and lower Spraberry.In our Powder River Basin program in Wyoming, we accelerated our delineation activity and expanded our acreage position byapproximately 38,000 net acres through multiple acquisitions during 2014. We increased our rig count throughout 2014, exiting theyear operating four drilling rigs.We have an ongoing exploration program to acquire leasehold and test concepts in new plays. In 2014, we continued toevaluate our exploration area in east Texas. We completed the construction of a gathering system in this area at the end of 2014 toallow for longer-term production tests on wells we have drilled and completed.Production Results. The table below provides a regional breakdown of our production for 2014: South Texas &Gulf Coast RockyMountain Permian Mid-Continent Total (1)Production: Oil (MMBbl)7.1 7.4 2.0 0.1 16.7Gas (Bcf)121.6 7.0 4.5 19.8 152.9NGLs (MMBbl)12.8 0.1 — 0.1 13.0Equivalent (MMBOE) (1)40.2 8.7 2.8 3.5 55.1Avg. Daily Equivalents (MBOE/d)110.1 23.9 7.6 9.5 151.1Relative percentage73% 16% 5% 6% 100%____________________________________________(1) Totals may not sum or recalculate due to rounding.We had record production in 2014, which was primarily driven by the continued development of our Eagle Ford shale andBakken/Three Forks programs. Please refer to Comparison of Financial Results and Trends between 2014 and 2013 below foradditional discussion on production.63Costs 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 EndedDecember 31, 2014 (in millions)Development costs$1,782.3Exploration costs288.3Acquisitions Proved properties272.9Unproved properties368.2Total, including asset retirement obligation (1)$2,711.7____________________________________________(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.The majority of our drilling and completion costs incurred during 2014 were in our Eagle Ford shale and Bakken/Three Forksprograms. During 2014, we incurred $561.6 million to acquire proved and unproved properties in our Gooseneck area in North Dakotaand in the Powder River Basin in Wyoming. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item8 of this report for additional discussion.Divestiture Activity. During the second quarter of 2014, we divested certain non-strategic assets in the Williston Basin located inour Rocky Mountain region. Total cash proceeds received at closing (referred throughout this report as “divestiture proceeds”)were $50.1 million and the final gain on this divestiture was $26.9 million. Please refer to Note 3 - Acquisitions, Divestitures, and AssetsHeld for Sale in Part II, Item 8 of this report for additional discussion.Impairment of Proved and Unproved Properties. We recorded impairment of proved properties expense of $84.5 million andabandonment and impairment of unproved properties expense of $75.6 million for the year ended December 31, 2014. This was aresult of the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wellsin certain prospects in our South Texas & Gulf Coast and Permian regions.2022 Notes. During 2014, we issued $600.0 million in aggregate principal amount of 6.125% Senior Notes. The notes wereissued at par and mature on November 15, 2022. We received net proceeds of $590.0 million from this issuance, which we used torepay outstanding borrowings under our credit facility and for general corporate purposes. Please refer to Note 5 - Long-term Debt inPart II, Item 8 of this report for additional discussion.Revolving Credit Facility. In the fourth quarter of 2014, the borrowing base under our credit facility was increased by ourlenders to $2.4 billion from $2.2 billion. Additionally, in December 2014 we entered into a Second Amendment to the Fifth Amendedand Restated Credit Agreement with our lenders, which resulted in an extension of the maturity date to December 10, 2019, and anincrease in current aggregate lender commitments to $1.5 billion. Please refer to Overview of Liquidity and Capital Resources belowfor additional discussion of our credit facility.Marketing of Properties. Subsequent to December 31, 2014, we announced our plan to exit the Mid-Continent region andbegan marketing our assets in the Arkoma Basin of Oklahoma and in the Arklatex area of east Texas and northern Louisiana.64Outlook for 2015We view 2015 as a year of transition as the broader oil and gas industry adjusts to lower oil prices. Exploration and productioncompanies are reducing drilling and completion activity, which we expect to result in service companies lowering the price for theirservices. Our plan for 2015 is to scale back activity over the course of the year while preserving the value of our assets and protectingthe strength of our balance sheet. Our goal is to be well positioned entering 2016 in what we expect will be a stronger commodity priceand lower service cost environment, while having the strength and flexibility to adapt should industry conditions worsen.Our capital program for 2015 will be approximately $1.2 billion, of which $1.0 billion will be invested in drilling andcompletion activities. We expect to focus 85 percent of our drilling and completion capital on our core development programs in theEagle Ford shale and the Bakken/Three Forks formations.In our operated Eagle Ford shale program, we expect to invest approximately $470 million in drilling and completion activitiesin 2015. Our plan is to operate four drilling rigs for the majority of the year and to complete wells in a manner that allows us to takeadvantage of cost reductions currently being realized and expected to continue throughout 2015 and into 2016. We expect we willcontinue to test the potential of the upper Eagle Ford interval throughout the year.In our outside-operated Eagle Ford shale program, we expect to invest approximately $135 million for drilling and completionactivities in 2015. Our expectation is that the operator will slow the pace of development in 2015. As our carry with Mitsui was fullyutilized in 2014, we will be responsible for funding our share of the costs for this program in 2015.We plan to invest $255 million in our Bakken/Three Forks program in 2015 for drilling and completion activities,approximately 75 percent of which will be on operated properties. We expect to reduce operated drilling activity over the course of theyear from a five rig program at the beginning of the year to a two rig program by year-end. We plan to focus more of our activity in ourGooseneck area in Divide County, North Dakota in 2015 to develop and delineate acreage that we added in 2014.Given current industry conditions, we are scaling back activity in our delineation and exploration programs in 2015. We expectour activity in the Powder River Basin, the Permian Basin, and east Texas will be reduced, and we will focus on preserving thoseacreage positions.We currently expect our 2015 capital program to be funded by cash flows from operations and proceeds from planneddivestitures, supplemented by borrowings under our credit facility. Please refer to Overview of Liquidity and Capital Resources belowfor additional discussion.65Financial Results of Operations and Additional Comparative DataThe tables below provide information regarding selected production and financial information for the quarter endedDecember 31, 2014, and the immediately preceding three quarters. A detailed discussion follows. For the Three Months Ended December 31, September 30, June 30, March 31, 2014 2014 2014 2014 (in millions, except for production data)Production (MMBOE)16.2 13.1 13.4 12.5Oil, gas, and NGL production revenue$586.6 $617.2 $654.7 $623.1Lease operating expense$75.3 $66.5 $62.8 $57.0Transportation costs$93.4 $81.5 $83.0 $79.2Production taxes$27.5 $30.4 $31.8 $27.5Depletion, depreciation, amortization, and assetretirement obligation liability accretion$219.3 $183.3 $187.8 $177.2Exploration$49.7 $34.6 $24.3 $21.3General and administrative$52.2 $41.7 $38.1 $35.1Net income$331.7 $208.9 $59.8 $65.6____________________________________________Note: Quarterly amounts may not calculate to annual amounts due to rounding.Selected Performance Metrics: For the Three Months Ended December 31, September 30, June 30, March 31, 2014 2014 2014 2014Average net daily production equivalent (MBOEper day)175.8 142.5 147.0 138.6Lease operating expense (per BOE)$4.66 $5.07 $4.69 $4.58Transportation costs (per BOE)$5.77 $6.22 $6.20 $6.35Production taxes as a percent of oil, gas, and NGLproduction revenue4.7% 4.9% 4.9% 4.4%Depletion, depreciation, amortization, and assetretirement obligation liability accretion (per BOE)$13.56 $13.97 $14.03 $14.21General and administrative (per BOE)$3.23 $3.18 $2.85 $2.81____________________________________________Note: Amounts may not recalculate due to rounding.66A year-to-year overview of selected production and financial information, including trends: For the Years Ended December 31, Amount Change Between Percent Change Between 2014 2013 2012 2014/2013 2013/2012 2014/2013 2013/2012Net production volumes (1) Oil (MMBbl)16.7 13.9 10.4 2.7 3.6 19 % 34 %Gas (Bcf)152.9 149.3 120.0 3.6 29.3 2 % 24 %NGLs (MMBbl)13.0 9.5 6.1 3.5 3.4 37 % 55 %Equivalent (MMBOE) (2)55.1 48.3 36.5 6.8 11.8 14 % 32 %Average net daily production (1) Oil (MBbl per day)45.6 38.2 28.3 7.4 9.9 19 % 35 %Gas (MMcf per day)419.0 409.2 328.0 9.8 81.2 2 % 25 %NGLs (MBbl per day)35.6 26.0 16.7 9.6 9.3 37 % 56 %Equivalent (MBOE per day) (2)151.1 132.4 99.7 18.6 32.7 14 % 33 %Oil, gas, and NGL production revenue (inmillions) Oil production revenue$1,348.3 $1,271.5 $886.2 $76.8 $385.3 6 % 43 %Gas production revenue699.8 586.3 357.7 113.5 228.6 19 % 64 %NGL production revenue433.4 341.8 230.0 91.6 111.8 27 % 49 %Total$2,481.5 $2,199.6 $1,473.9 $281.9 $725.7 13 % 49 %Oil, gas, and NGL production expense (inmillions) Lease operating expense$261.6 $233.0 $180.1 $28.6 $52.9 12 % 29 %Transportation costs337.1 258.2 138.9 78.9 119.3 31 % 86 %Production taxes117.2 105.8 72.9 11.4 32.9 11 % 45 %Total$715.9 $597.0 $391.9 $118.9 $205.1 20 % 52 %Realized price Oil (per Bbl)$80.97 $91.19 $85.45 $(10.22) $5.74 (11)% 7 %Gas (per Mcf)$4.58 $3.93 $2.98 $0.65 $0.95 17 % 32 %NGLs (per Bbl)$33.34 $35.95 $37.61 $(2.61) $(1.66) (7)% (4)%Per BOE (2)$45.01 $45.50 $40.39 $(0.49) $5.11 (1)% 13 %Per BOE data (2) Production costs: Lease operating expense$4.74 $4.82 $4.93 $(0.08) $(0.11) (2)% (2)% Transportation costs$6.11 $5.34 $3.81 $0.77 $1.53 14 % 40 % Production taxes$2.13 $2.19 $2.00 $(0.06) $0.19 (3)% 10 %General and administrative$3.03 $3.09 $3.28 $(0.06) $(0.19) (2)% (6)%Depletion, depreciation, amortization,and asset retirement obligation liabilityaccretion$13.92 $17.02 $19.95 $(3.10) $(2.93) (18)% (15)%Derivative settlement gain (3)$0.22 $0.42 $1.32 $(0.20) $(0.90) (48)% (68)% Earnings per share information Basic net income (loss) per common share$9.91 $2.57 $(0.83) $7.34 $3.40 286 % 410 %Diluted net income (loss) per commonshare$9.79 $2.51 $(0.83) $7.28 $3.34 290 % 402 %Basic weighted-average common sharesoutstanding (in thousands)67,230 66,615 65,138 615 1,477 1 % 2 %Diluted weighted-average common sharesoutstanding (in thousands)68,044 67,998 65,138 46 2,860 — % 4 %67____________________________________________(1) Amounts and percentage changes may not recalculate due to rounding.(2) 2012 equivalent volumes and per-unit metrics have been conformed to current year presentation on a BOE basis rather than an MCFE basis.(3) We discontinued hedge accounting on January 1, 2011. As a result, fair values at December 31, 2010, were frozen in accumulated other comprehensiveloss (“AOCL”) and were reclassified into earnings as the original derivative transactions settled, the last of which settled in the third quarter of 2013. For theyears ended December 31, 2013, and 2012, derivative settlements are included within the other operating revenues and derivative gain line items in theaccompanying statements of operations. All derivative settlements for the year ended December 31, 2014, are included within the derivative gain line itemonly.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 31,2014, increased 14 percent compared to the same period in 2013, driven by continued development of our Eagle Ford shale assets.Please refer to Comparison of Financial Results and Trends between 2014 and 2013 below for additional discussion on changes in ourproduction mix in 2014.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, 2014, decreased slightly compared to the same period in 2013. Our derivative contractshad a favorable impact on our average realized price, after the effects of derivative settlements, in the last half of 2014 in light of thesignificant decline in commodity prices.Lease operating expense (“LOE”) on a per BOE basis for the year ended December 31, 2014, decreased two percent comparedto the same period in 2013. Overall, LOE increased; however, production increased at a faster rate, resulting in reduced LOE on a perBOE basis. We experience volatility in our LOE as a result of seasonality in workover expense and the impact that industry activity hason service provider costs. For 2015, we expect a decrease in service provider costs in response to the weak commodity priceenvironment. We anticipate an increase in production in 2015 based on our forecasted drilling plan. Both of these projected trends areexpected to drive our LOE on a per BOE basis down in 2015.Transportation costs on a per BOE basis for the year ended December 31, 2014, increased 14 percent compared to the sameperiod in 2013. Our Eagle Ford shale program has meaningfully higher transportation expense per unit of production compared to 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. The run-rate of our perunit transportation cost in the Eagle Ford shale program increased in 2014 due to incremental compression charges and increasedvariable fuel costs associated with higher natural gas prices. Additionally, our transportation arrangements have shifted over the yearsto contracts that have more favorable terms for product prices but also include higher transportation fees. We expect this upward trendin transportation costs on a per BOE basis to continue in 2015.Production taxes on a per BOE basis for the year ended December 31, 2014, decreased three percent compared to the sameperiod in 2013. We generally expect absolute production tax expense to trend with oil, gas, and NGL production revenue. Product mix,the location of production, and incentives to encourage oil and gas development can all impact or change the amount of production taxwe recognize. General and administrative expense on a per BOE basis for the year ended December 31, 2014, decreased two percentcompared to the same period in 2013, as production increased at a faster rate than our general and administrative expense. A portion ofour general and administrative expense is linked to our profitability and cash flow, which are driven in large part by the realizedcommodity prices we receive for our production. A portion of our short-term incentive compensation correlates with net cash flows andtherefore is subject to variability. In 2015, we expect general and administrative expense on a per BOE basis will decrease, as weanticipate production will continue to increase at a faster rate than our increase in absolute general and administrative expense.68Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense, for the year endedDecember 31, 2014, decreased 18 percent, on a per BOE basis, compared to the same period in 2013. Our DD&A rate can fluctuate asa result of impairments, planned and closed divestitures, and changes in the mix of our production and the underlying proved reservevolumes. Our DD&A rate has decreased 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, for the last several years and throughout the first halfof 2014, we added reserves with minimal associated costs due to our carry with Mitsui under our Acquisition and DevelopmentAgreement. This carry was exhausted during the second quarter of 2014. We expect our DD&A rate to increase in future periods as webegin to record our full share of costs in our outside-operated Eagle Ford shale program, which will increase our depletable asset base.Please refer to Note 12 - Acquisition and Development Agreement in Part II, Item 8 of this report for additional discussion on the Mitsuitransaction.Please refer to Comparison of Financial Results and Trends between 2014 and 2013 for additional discussion on oil, gas, andNGL production expense, DD&A expense, and general and administrative expense. 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, 2012. Consequently, our in-the-money stock options, unvestedRSUs, and contingent PSUs were anti-dilutive for the year ended December 31, 2012, resulting in an increase in the diluted weighted-average common shares outstanding for the year ended December 31, 2013, when compared to 2012.Comparison of Financial Results and Trends between 2014 and 2013Oil, gas, and NGL production. The following table presents the regional changes in our production and oil, gas, and NGLproduction revenues and production costs between the years ended December 31, 2014, and 2013: Average Net DailyProduction Added(Lost) Oil, Gas & NGLRevenue Added (Lost) Production CostsIncrease (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 far exceeded the production decrease in our Mid-Continentregion, which resulted from the divestiture of our assets in the Anadarko Basin in December 2013.A 14 percent increase in production 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. Based on our planned drilling and completion activity, we expectproduction volumes to increase in 2015. We expect our realized price, before the effects of derivative settlements, to trend withcommodity prices.69Gain (loss) on divestiture activity. We recorded a net gain on divestiture activity of $646,000 for the year ended December 31,2014, compared with a net gain of $28.0 million in 2013. The net gain on divestiture activity for the year ended December 31, 2014, isdue to a gain realized on the sale of non-strategic properties in the Williston Basin in our Rocky Mountain region during the secondquarter of 2014 of $26.9 million, which was mostly offset by write downs recorded on assets classified as held for sale in the secondand third quarters of 2014. The net gain on divestiture activity for the year ended December 31, 2013, is largely due to gains recordedon the divestiture of certain assets in our Mid-Continent and Rocky Mountain regions slightly offset by a loss recorded on thedivestiture of non-strategic assets in our Permian region. We will continue to evaluate our portfolio to determine whether there are non-strategic properties we could divest. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of thisreport for additional discussion.Marketed gas system revenue and expense. Marketed gas system revenue decreased to $24.9 million for the year endedDecember 31, 2014, compared with $60.0 million for the comparable period of 2013. Concurrent with the decrease in marketed gassystem revenue, marketed gas system expense decreased to $24.5 million for the year ended December 31, 2014, from $57.6 millionfor the comparable period of 2013. The decrease occurred primarily as a result of the divestiture of our assets in the Anadarko Basin inDecember 2013, which reduced marketed gas volumes and the overall significance of marketed gas system revenues and expenses. Weexpect marketed gas revenue and expense to correlate with changes in production and our realized gas price throughout 2015.Subsequent to December 31, 2014, we announced our plan to exit the Mid-Continent region and sell our Arkoma Basin and Arklatexassets. If we successfully divest these assets, our marketed gas volumes will be eliminated.Other operating revenues. Other operating revenues increased to $15.2 million for the year ended December 31, 2014,compared with $5.8 million for the comparable period of 2013. We recorded a $10.7 million gain in the second quarter of 2014 relatedto our settlement with Endeavour Operating Corporation (“Endeavour”), in which we, our working interest partners, and Endeavouragreed to mutually release all claims and dismiss certain litigation in exchange for certain cash payments and other consideration.Oil, gas, and NGL production expense. Total production costs increased $118.9 million, or 20 percent, to $715.9 million for theyear ended December 31, 2014, compared with $597.0 million in 2013, primarily due to a 14 percent increase in production volumeson a per BOE basis, as well as an overall increase in transportation costs in our South Texas & Gulf Coast region. Please refer to thecaption A year-to-year overview of selected production and financial information, including trends above for discussion of productioncosts on a per BOE basis.Depletion, depreciation, amortization, and asset retirement obligation liability accretion. DD&A expense decreased sevenpercent to $767.5 million in 2014 compared with $822.9 million in 2013. Please refer to our caption A year-to-year overview ofselected production and financial information, including trends above for discussion of DD&A expense on a per BOE basis.Exploration. The components of exploration expense are summarized as follows: For the Years Ended December 31, 2014 2013Summary of Exploration Expense(in millions)Geological and geophysical expenses$11.4 $4.3Exploratory dry hole44.4 5.8Overhead and other expenses74.1 64.0Total$129.9 $74.170Exploration expense for 2014 increased 75 percent compared with the same period in 2013 mainly due to expensing threeexploratory dry holes in certain prospects in our South Texas & Gulf Coast region in 2014. An exploratory project resulting in non-commercial quantities of oil, gas, or NGLs is deemed an exploratory dry hole and impacts the amount of exploration expense werecord. We have an active exploration program, which can result in periodic dry hole expense. During the first quarter of 2014, weperformed a seismic study in our Powder River Basin program, which resulted in increased geological and geophysical (“G&G”)expenses year over year. We have also experienced an overall increase in exploration overhead.Impairment of proved properties. We recorded impairment of proved properties expense of $84.5 million for the year endedDecember 31, 2014. The impairments recorded in 2014 were a result of the significant decline in commodity prices in late 2014 andrecognition of the outcomes of exploration and delineation wells in certain prospects in our South Texas & Gulf Coast and Permianregions. We recorded impairment of proved properties expense of $172.6 million for the comparable period in 2013 as a result ofnegative engineering revisions on our Mississippian limestone assets in our Permian region at the end of the year, the commencementof a plugging and abandonment program of dry gas assets in the Olmos interval in our South Texas & Gulf Coast region, and ourdecision to no longer pursue the development of certain under-performing assets during the year. Future crude oil, natural gas, andNGL price declines, downward engineering revisions, or unsuccessful exploration efforts may result in additional proved propertyimpairments.Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved propertiesexpense of $75.6 million for the year ended December 31, 2014, related to acreage we no longer intended to develop as a result ofexploration and delineation activities and changes to our drilling plans in light of the recent decline in commodity prices. We recorded$46.1 million of abandonment and impairment of unproved properties expense for the comparable period in 2013, the majority ofwhich related to acreage we no longer intended to develop in our Permian region. We expect our abandonment and impairment ofunproved properties expense to fluctuate with the timing of lease expirations, unsuccessful exploration activities, and changes indrilling plans if commodity prices remain low.General and administrative. General and administrative expense increased to $167.1 million for the year ended December 31,2014, compared with $149.6 million for the same period in 2013. The increase is due to an increase in employee headcount during2014, which resulted in increased base compensation, benefits, and general corporate office expenses. Please refer to our caption Ayear-to-year overview of selected production and financial information, including trends above for discussion of general andadministrative costs on a per BOE basis.Change in Net Profits Plan liability. This non-cash expense (benefit) generally relates to the change in the estimated value of theassociated liability between the reporting periods. For 2014, we recorded a non-cash benefit of $29.8 million compared to a non-cashbenefit of $21.8 million in 2013. The increase in the benefit between these two periods is mostly due to the decrease in commodity strippricing as of December 31, 2014, as compared to December 31, 2013. The change in our liability is subject to estimation and maychange from period to period based on assumptions used for production rates, reserve quantities, commodity pricing, discount rates,and production costs. We generally expect the change in our Net Profits Plan liability to correlate with fluctuations in commodity prices.Derivative gain. We recognized a derivative gain of $583.3 million for the year ended December 31, 2014, consisting of a$12.6 million gain on settlements and a $570.7 million increase in the fair value of commodity derivative contracts driven by thesignificant decline in oil and gas commodity strip pricing in the fourth quarter of 2014. This compares to a net derivative gain of $3.1million for the same period in 2013, which consists of a $22.1 million gain on settlements and a $19.0 million decrease in the fair valueof commodity derivative contracts during the period. Please refer to Note 10 - Derivative Financial Instruments in Part II, Item 8 of thisreport for additional discussion.71Other operating expenses. Other operating expenses were $4.7 million in 2014 compared with $30.1 million in 2013. In 2013,other operating expenses included $23.1 million of expenses related to an agreed clarification concerning royalty payment provisionsof various leases on certain South Texas & Gulf Coast acreage.Income tax (expense) benefit. We recorded income tax expense of $398.6 million for 2014 compared to income tax expense of$107.7 million for 2013, resulting in effective tax rates of 37.4 percent and 38.6 percent, respectively. The increase in tax expense forthe year ended December 31, 2014, generally trends with the increase in net income. The net decrease in tax rate is partially attributableto our 2013 Anadarko Basin divestiture which caused a decrease in the composition of our blended state tax rate for future years offsetby an increase in our valuation allowance on state net operating losses in 2014. However, state cash taxes are lower as a result of adecrease in estimated Texas margin tax. Please refer to Note 4 - Income Taxes in Part II, Item 8 of this report for additional discussion.State apportionment factor changes in 2015 and the likelihood we will file amended returns to claim additional research anddevelopment (“R&D”) credits are expected to result in a lower effective tax rate in 2015.Comparison of Financial Results and Trends between 2013 and 2012Oil, gas and NGL production. The following table presents the regional changes in our production and oil, gas, and NGLproduction revenues and production costs between the years ended December 31, 2013 and 2012: Average Net DailyProduction Added (Lost) Oil, Gas & NGL RevenueAdded Production Costs Increase(Decrease) (MBOE/d) (in millions) (in millions)South Texas & Gulf Coast33.4 $515.5 $159.2Rocky Mountain3.4 136.6 28.7Permian1.4 51.6 19.4Mid-Continent(5.5) 22.0 (2.2)Total32.7 $725.7 $205.1The largest regional production increase in 2013 occurred in our South Texas & Gulf Coast region as a result of drilling activityin our Eagle Ford shale program. The increase in oil and gas prices caused an increase in oil, gas, and NGL production revenue in ourMid-Continent region between the years ended December 31, 2013, and 2012, despite a decrease in production volumes attributable tobase decline.A 32 percent increase in production on an equivalent basis combined with a 13 percent increase in realized price per BOEresulted in a 49 percent increase in revenue between the two periods.Gain (loss) on divestiture activity. We recorded a net gain on divestiture activity of $28.0 million for the year endedDecember 31, 2013, compared with a net loss of $27.0 million for the comparable period of 2012. The net gain on divestiture activityfor the year ended December 31, 2013, was largely due to gains recorded on the divestiture of certain assets in our Mid-Continent andRocky Mountain regions slightly offset by a loss recorded on the divestiture of non-strategic assets in our Permian region. The net lossfor the year ended December 31, 2012, was due to an unsuccessful property sale effort and the corresponding write-down of thoseassets held for sale to their fair value. This loss was partially offset by a net gain on completed divestitures. Please refer to Note 3 -Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of this report for additional discussion.Marketed gas system revenue and expense. Marketed gas system revenue increased to $60.0 million for the year endedDecember 31, 2013, compared with $52.8 million for the comparable period of 2012, as a result of an increase in gas prices.Concurrent with the increase in marketed gas system revenue, marketed gas system expense increased to $57.6 million for the yearended December 31, 2013, from $47.6 million for the comparable period of722012. The decrease in our net margin was due to an increase in gathering fees paid to third parties, which went into effect in the secondhalf of 2012.Oil, gas, and NGL production expense. Total production costs increased $205.1 million, or 52 percent, to $597.0 million for theyear ended December 31, 2013, compared with $391.9 million in 2012, primarily due to a 32 percent increase in production volumeson 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 accretion. DD&A expense increased 13 percentto $822.9 million in 2013, compared with $727.9 million in 2012, as a result of the continued development of our Eagle Ford andBakken/Three Forks assets and the associated growth in our production, partially offset by the sale of our Anadarko Basin propertiesthat were classified as held for sale at the beginning of the third quarter of 2013.Exploration. The components of exploration expense are summarized as follows: For the Years Ended December 31, 2013 2012Summary of Exploration Expense(in millions)Geological and geophysical expenses$4.3 $13.6Exploratory dry hole5.8 20.9Overhead and other expenses64.0 55.7Total$74.1 $90.2Exploration expense for 2013 decreased 18 percent compared with the same period in 2012 as a result of decreased G&G dueto a large seismic study conducted in the first quarter of 2012 and fewer exploratory dry holes expensed in 2013, partially offset by anincrease in exploration overhead in 2013 mainly due to an increase in performance-based compensation.Impairment of proved properties. We recorded impairment of proved properties expense of $172.6 million for the year endedDecember 31, 2013. The impairments in 2013 were a result of negative engineering revisions on Mississippian limestone assets in ourPermian region at the end of the year, the commencement of a plugging and abandonment program of dry gas assets in the Olmosinterval in our South Texas & Gulf Coast region, and our decision to no longer pursue the development of certain under-performingassets during the year. We recorded impairment of proved properties expense of $208.9 million for the comparable period in 2012related to write-downs of our Wolfberry assets in our Permian region due to downward engineering revisions, as well as write-downs ofour Haynesville shale assets due to low natural gas prices.Abandonment and impairment of unproved properties. We recorded abandonment and impairment of unproved propertiesexpense of $46.1 million for the year ended December 31, 2013, the majority of which related to acreage we no longer intended todevelop in our Permian region. We recorded $16.3 million of abandonment and impairment of unproved properties expense for thecomparable period in 2012, the majority of which related to acreage we no longer intended to develop in our Rocky Mountain and Mid-Continent regions.General and administrative. General and administrative expense increased to $149.6 million for the year ended December 31,2013, compared with $119.8 million for the same period in 2012. The increase was due to an increase in performance-basedcompensation that reflects exceeding our performance metrics, as well as an increase in employee headcount during 2013, whichresulted in increased base compensation, benefits, and general corporate office expenses. These were slightly offset by an increase inCOPAS overhead reimbursement as a result of an increase in operated well count.73Change in Net Profits Plan liability. For 2013, we recorded a non-cash benefit of $21.8 million compared to a non-cash benefitof $28.9 million in 2012. Please refer to Comparison of Financial Results and Trends between 2014 and 2013 above for additionaldiscussion on the assumptions used in estimating the liability.Derivative gain. We recognized a derivative gain of $3.1 million for the year ended December 31, 2013, which was comprisedof a $22.1 million gain on settlements and a $19.0 million decrease in the fair value of commodity derivative contracts during theperiod. This compares to a gain of $55.6 million for the same period in 2012, which consisted of a $44.3 million gain on settlementsand an $11.4 million increase in the fair value of commodity derivative contracts during the period. Please refer to Note 10 - DerivativeFinancial Instruments in Part II, Item 8 of this report for additional discussion.Other operating expenses. Other operating expenses were $30.1 million in 2013 compared with $7.0 million in 2012. In 2013,other operating expenses included $23.1 million of expenses related to an agreed clarification concerning royalty payment provisionsof various leases on certain South Texas & Gulf Coast acreage.Income tax (expense) benefit. We recorded income tax expense of $107.7 million for 2013 compared to income tax benefit of$29.3 million for 2012, resulting in effective tax rates of 38.6 percent and 35.0 percent, respectively. The 2013 rate increase resultedprimarily from the Anadarko Basin divestiture that closed at the end of 2013, which caused a shift in anticipated recognition of futurestate tax benefits from a state with a higher applicable state rate to states with lower applicable rates. A combination of lower enactedstate income tax rates during the year and a shift between states of our anticipated future apportioned income caused a decrease in ouroverall state rate which partially offset the increase. Other factors impacting our effective tax rate between tax years include decreasedimpact for valuation allowances, a decreased impact in benefit from the R&D credit, and to a much lesser extent, net decreases resultingfrom the differing effects of percentage depletion and other permanent differences.Overview of Liquidity and Capital ResourcesWe believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future. Wecontinue to manage the duration and level of our drilling and completion service commitments in order to provide expected flexibilityto reduce activity and capital expenditures in periods of prolonged commodity price decline.Sources of cashWe currently expect our 2015 capital program to be funded by cash flows from operations and proceeds from planneddivestitures, supplemented by borrowings under our credit facility. Although we anticipate that cash flows from these sources will besufficient to fund our expected 2015 capital program, we may also elect to access the capital markets, depending on prevailing marketconditions, as well as divest of additional non-strategic oil and gas properties to provide additional sources of funding. From time totime, we may enter into carrying cost funding and sharing arrangements with third parties for particular exploration and/or developmentprograms. All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations incommodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the marketprices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL salesthrough the use of derivative contracts as part of our commodity price risk management program. Historically, decreases in commodityprices have limited our industry’s access to capital markets. The borrowing base under our credit facility could be reduced as a result oflower commodity prices, divestitures of proved properties, or newly issued debt. See Credit facility below for a discussion of our mostrecent borrowing base redetermination.In the fourth quarter of 2014, we issued $600.0 million in aggregate principal amount of 2022 Notes and amended our creditfacility agreement, resulting in an extended maturity date and an increased aggregate lender commitment amount.74In late 2011, we consummated our Acquisition and Development Agreement with Mitsui, pursuant to which Mitsui funded, orcarried, 90 percent of certain drilling and completion costs attributable to our remaining interest in our non-operated Eagle Ford shaleacreage until $680.0 million was expended on our behalf. Our remaining 10 percent was funded over the carry period with thereimbursement of net costs paid attributable to the transferred interest during the period between the effective date and the closing date.The remaining carry was utilized during the second quarter of 2014, at which point we became responsible for funding our share ofdrilling and completion costs.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, thesefunding reductions could have a significant adverse effect on drilling in the United States for a number of years.Credit facilityDuring the fourth quarter of 2014, we and our lenders entered into a Second Amendment to our Fifth Amended and RestatedCredit Agreement. As amended, the credit facility has a maximum loan amount of $2.5 billion, current aggregate lender commitmentsof $1.5 billion, and a maturity date of December 10, 2019. On October 6, 2014, the lending group redetermined the Company'sborrowing base under the credit facility and increased it from $2.2 billion to $2.4 billion. The subsequent amendment to the creditfacility specified that the borrowing base would not be reduced by the issuance of the 2022 Notes and will remain at $2.4 billion untilthe next scheduled redetermination date of April 1, 2015. The borrowing base redetermination process under the credit facilityconsiders the value of the Company’s proved oil and gas properties, as determined by the lender group. We believe the currentcommitment amount is sufficient to meet our anticipated liquidity and operating needs. No individual bank participating in our creditfacility represents more than 10 percent of the lending commitments under the credit facility. Borrowings under our credit facility aresecured by mortgages on at least 75 percent of the value of our proved oil and gas properties. Please refer to Note 5 - Long-term Debt inPart II, Item 8 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters ofcredit, and available borrowing capacity under our credit facility as of February 18, 2015, December 31, 2014, and December 31, 2013. 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 less than1.0. Please refer to the caption Non-GAAP Financial Measures below. As of the filing date of this report, we are in compliance with allfinancial and non-financial covenants under our credit facility.Operating cash flow and cash received from the divestiture of properties were sufficient in meeting our capital expenditureneeds through the first half of 2014. During the third quarter of 2014, we began to draw upon our credit facility, primarily to fundacquisitions of oil and gas properties. Our daily weighted-average credit facility debt balance was approximately $86.6 million and$192.4 million for the years ended December 31, 2014, and 2013, respectively. Our daily weighted-average credit facility balance waslower throughout 2014 as a result of proceeds received from property divestitures in the fourth quarter of 2013. In addition, we used theproceeds from our 2022 Notes to reduce our credit facility balance in the fourth quarter of 2014. Cash flows provided by our operatingactivities, proceeds received from divestitures of properties, and the amount of our capital expenditures all impact the amount we haveborrowed under our credit facility.75Weighted-average interest ratesOur calculated weighted-average interest rates include paid and accrued interest, fees on the unused portion of the creditfacility’s aggregate commitment amount, letter of credit fees, and the non-cash amortization of deferred financing costs. Additionally,our 2012 weighted-average interest rate includes amortization of the debt discount related to our 3.50% Senior Convertible Notes due2027 (the “3.50% Senior Convertible Notes”). Our calculated weighted-average borrowing 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, 2014, 2013, and 2012. For the Years Ended December 31, 2014 2013 2012Weighted-average interest rate6.5% 6.3% 6.4%Weighted-average borrowing rate5.9% 5.7% 5.5%Our weighted-average interest rates and weighted average borrowing rates for the years ended December 31, 2014, 2013, and2012, have been impacted by the timing of Senior Notes issuances in 2014 and prior years, the average balance on our revolving creditfacility, and the fees paid on the unused portion of our aggregate commitment.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 exploration anddevelopment of oil and gas properties are the primary use of our capital resources. During 2014, we spent $2.5 billion for explorationand development capital activities and proved and unproved oil and gas property acquisitions. These amounts differ from the costincurred amounts, 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 development and exploratory 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.We 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.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 reviews this program as part of the allocation of our capital. During 2014, we did notrepurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares.76During 2014, we paid $6.7 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. Payment of future dividends remains at the discretion of ourBoard of Directors. The following table presents changes in cash flows between the years ended December 31, 2014, 2013, and 2012, for ouroperating, investing, and financing activities. The analysis following the table should be read in conjunction with our consolidatedstatements of cash flows in Part II, Item 8 of this report. For the Years EndedDecember 31, Amount of Changes Between Percent of Change Between 2014 2013 2012 2014/2013 2013/2012 2014/2013 2013/2012 (in millions) Net cash providedby operatingactivities $1,456.6 $1,338.5 $922.0 $118.1 $416.5 9% 45 %Net cash used ininvesting activities $(2,478.7) $(1,192.9) $(1,457.3) $(1,285.8) $264.4 108% (18)%Net cash providedby financingactivities $740.0 $130.7 $422.1 $609.3 $(291.4) 466% (69)%Analysis of cash flow changes between 2014 and 2013Operating activities. Cash received from oil, gas, and NGL production revenues, net of transportation costs and productiontaxes, including derivative cash settlements, increased $256.0 million, or 14 percent, to $2.0 billion for the year ended December 31,2014, compared with the same period in 2013. Cash paid for lease operating expenses in 2014 increased $20.6 million from 2013.These increases were driven by a 14 percent increase in production volumes. Cash paid for interest, net of capitalized interest, increased$18.4 million during 2014 compared with the same period in 2013 due to the first interest payment on our 2024 Notes issued in 2013being made in the first quarter of 2014. Additionally, cash bonuses paid in 2014 for the 2013 performance year were $41.8 millioncompared to $16.3 million paid in 2013 for the 2012 performance year. These changes are offset by a decrease in other operatingworking capital in 2014.Investing activities. Capital expenditures in 2014 increased $421.3 million, or 27 percent, compared with the same period in2013 due to increased spending in our Eagle Ford shale and Bakken/Three Forks programs. Acquisitions of proved and unprovedproperties increased $483.0 million as a result of property acquisitions in our Gooseneck area and the Powder River Basin in 2014. Netproceeds from the sale of oil and gas properties in 2014 decreased $381.0 million compared to the same period in 2013 due largely tothe sale of our Anadarko Basin assets in the fourth quarter of 2013.Financing activities. We received $590.0 million of net proceeds from the issuance of our 2022 Notes in 2014, compared with$490.2 million of net proceeds from the issuance of our 2024 Notes in 2013. These proceeds were used to repay outstandingborrowings under our credit facility and for general corporate purposes. We had net borrowings under our credit facility of $166.0million during the year ended December 31, 2014, compared with net payments of $340.0 million during the same period in 2013.77Analysis of cash flow changes between 2013 and 2012Operating activities. Cash received from oil, gas, and NGL production revenues, including derivative cash settlements,increased $652.6 million, or 43 percent, to $2.2 billion for the year ended December 31, 2013, compared with the same period in 2012.Cash paid for lease operating expenses in 2013 increased $54.5 million from 2012. These increases were driven by a 32 percentincrease in production volumes. Cash paid for interest, net of capitalized interest, during 2013 increased $19.4 million compared withthe same period in 2012 due to interest paid on our 2023 Notes issued in 2012 in the first and third quarters of 2013, offset partially byinterest no longer paid on the 3.50% Senior Convertible Notes that we settled in April 2012.Investing activities. Net proceeds from the sale of oil and gas properties in 2013 increased $369.5 million compared to the sameperiod in 2012 due largely to the sale of our Anadarko Basin assets in the fourth quarter of 2013. Capital expenditures in 2013,including costs to acquire proved and unproved oil and gas properties, increased $101.5 million, or seven percent, compared with thesame period in 2012. This increase is primarily the result of our completed acquisition of proved and unproved properties in our RockyMountain region in the second quarter of 2013.Financing activities. We received $490.2 million of net proceeds from the issuance of our 2024 Notes in 2013, compared with$392.1 million of net proceeds from the issuance of our 2023 Notes in 2012. These proceeds were used to repay outstandingborrowings under our credit facility and for general corporate purposes. We had net payments under our credit facility of $340.0million during the year ended December 31, 2013, compared with net borrowings of $340.0 million during the same period in 2012.During the second quarter of 2012, we paid $287.5 million to settle our 3.50% Senior Convertible Notes.Interest Rate RiskWe are exposed to market risk due to the floating interest rate on our revolving credit facility. Our credit agreement allows us tofix 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, 2014, our fixed-rate debt and floating-rate debt outstanding totaled $2.2 billion and $166.0 million, respectively. The carrying amount of our floating-rate debt at December 31, 2014, approximates its fair value. Assuming a constant floating-rate debt level of $166.0 million, the before-tax cash flow impact resulting from a 100 basis point change in our interest rate would be $1.7 million over a 12-month period.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 relatively minor changes in supplyand demand. The markets for oil, gas, and NGLs have been volatile, especially in recent months, and these markets will likely continueto be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Based on our2014 production, a 10 percent decrease in our average realized price, before the effects of derivative settlements, would have reducedour oil, gas, and NGL production revenues by $134.8 million, $70.0 million, and $43.3 million, respectively.78We enter into commodity derivative contracts in order to reduce the impact of fluctuations in commodity prices. Please refer toNote 10 – Derivative Financial Instruments of Part II, Item 8 of this report for additional information about our oil, gas, and NGLderivative contracts.The fair values of our commodity derivative contracts are largely determined by estimates of the forward curves of the relevantprice indices. At December 31, 2014, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGLcommodity derivative instruments would have changed our net asset positions by approximately $85 million, $78 million, and $2million, respectively.Schedule of Contractual ObligationsThe following table summarizes our contractual obligations at December 31, 2014, for the periods specified (in millions):Contractual Obligations Total Less than 1year 1-3 years 3-5 years More than 5yearsLong-term debt (1) $2,366.0 $— $— $516.0 $1,850.0Interest payments (2) 1,051.1 140.7 281.5 269.5 359.4Delivery commitments (3) 939.4 113.5 227.0 245.4 353.5Operating leases and contracts (3) 197.1 111.4 39.2 16.4 30.1Net Profits Plan (4) 28.1 5.9 10.1 8.4 3.7Asset retirement obligations (5) 152.3 28.4 4.0 7.6 112.3Other (6) 31.9 6.0 10.5 12.1 3.3Total $4,765.9 $405.9 $572.3 $1,075.4 $2,712.3____________________________________________(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, 2014, and assume no futureborrowing or repayment 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 through-put commitments.(4) Amounts shown represent undiscounted forecasted payments for the Net Profits Plan for the next six years. Payments are expected to gradually decreasefor the years beyond what are shown in this table and are not included due to these payments being highly variable, as outlined below. The amountrecorded on the accompanying consolidated balance sheets reflects all future Net Profits Plan payments and the impact of discounting, and thereforediffers from the amounts disclosed in this table. The variability in the amount of payments will be a direct reflection of commodity prices, productionrates, capital expenditures, and operating costs in future periods. Predicting the timing and amounts of payments associated with this liability iscontingent upon estimates of appropriate discount factors, adjusting for risk and time value, and upon a number of factors we cannot control. Please referto Note 7 – Compensation Plans and Note 11 - Fair Value Measurements in Part II, Item 8 of this report for additional discussion regarding our NetProfits Plan liability.(5)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, 2014. 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, 2014, areshown as an obligation in 2015 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.(6) The majority of the amount shown relates to the unfunded portion of our estimated pension liability of $29.9 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 2015 of $5.8million. Other amounts include the liability portion of the marked-to-market value of our commodity derivatives based on estimates of the forwardcurves of the relevant price indices at December 31, 2014, and excludes estimated oil, gas, and NGL commodity derivative receipts.79Off-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 2014 or 2013.Critical 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 and theestimate of our Net Profits Plan liability. Future cash inflows and future production and development costs are determined by applyingprices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimatedquantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to presentvalue using an appropriate discount rate. For example, the standardized measure calculations require a 10 percent discount rate to beapplied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are moreimprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. Weengage Ryder Scott, an independent reservoir-evaluation consulting firm, to audit at least 80 percent of our total calculated provedreserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity pricesand operating and capital costs change. We evaluate and estimate our proved reserves each year-end. For purposes of depletion andimpairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. Changes in depletionor impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period the reserve estimateschange. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report.80The 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. For the Years Ended December 31, 2014 2013 2012 MMBOE MMBOE MMBOE Change Change ChangeRevisions resulting from price changes3.4 0.6 (12.1)Revisions resulting from performance (1)7.0 4.4 (15.3)Total10.4 5.0 (27.4)____________________________________________(1) Performance revisions include the removal of proved undeveloped reserves that are no longer in our development plan within five years.As 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.The 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, 2014 2013 2012 MMBOE Percentage MMBOE Percentage MMBOE Percentage Change Change Change Change Change Change10% decrease in SECpricing(9.6) (2)% (9.8) (2)% (11.2) (4)%10% decrease in provedundeveloped reserves(26.1) (5)% (22.0) (5)% (12.7) (4)%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 or changes infuture service or equipment costs. Additional reserve information can be found in the reserve table and discussion included in Items 1and 2 of Part I of this report, and in Supplemental Oil and Gas Information of Part 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.81Revenue 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, their historical performance,NYMEX, local spot market, and OPIS prices, and other factors as the basis for these estimates. Variances between our estimates and theactual amounts received are recorded in the month payment is received. A 10 percent change in our year end revenue accrual wouldhave impacted total operating revenues by approximately $18 million in 2014.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 economic lives of our properties, estimate future inflation rates, and determine what credit-adjusted risk-free discount rate to use.The impact to the accompanying consolidated statements of operations from these estimates is reflected in our depreciation, depletion,and amortization calculations and occurs over the remaining life of our respective oil and gas properties. Please refer to Note 9 – AssetRetirement 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 to determine if the carrying amount is recoverable. If the carrying amount exceeds theestimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factorsused to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates,estimated future operating and capital expenditures, 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.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.82Income 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 loss carryforwardsand carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in theperiods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liabilitysettlement could have an impact on our results of operations. A one percent change in our effective tax rate would have changed ourcalculated income tax expense by approximately $10.6 million for the year ended December 31, 2014.Accounting MattersPlease refer to the section entitled Recently Issued Accounting Standards under Note 1 – Summary of Significant AccountingPolicies for additional information on the recent adoption of new authoritative accounting guidance in Part II, Item 8 of this report.EnvironmentalWe 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 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 regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recentlyadopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions ofgreenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationarysources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specifiedlarge greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 foremissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis,beginning in 2012 for emissions occurring in 2011.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. These actions include acommitment from the EPA to issue new source performance standards for methane emissions from the oil and gas sector. The EPAplans to propose the rule in 2015 and finalize the standards in 2016. The EPA has not committed to proposing existing source standardsfor the oil and gas sector. In addition, President Obama directed the EPA to issue stringent carbon standards for new fossil fuel-firedpower plants. The EPA proposed new source performance standards in September 2013, which would require carbon capture andsequestration for coal-fired boilers and combined cycle technology for natural gas-fired83boilers. The EPA plans to finalize the new source performance standards in the summer of 2015. In June 2014, the EPA proposedexisting source performance standards as stringent state emission “goals.” The proposed standards focus on re-dispatching electricityfrom coal-fired units to natural gas combined cycle plants and renewables. The EPA plans to finalize the rule in the summer of 2015,with state plans to implement and enforce the standards in 2016.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 acquire emissions allowances, or comply with newregulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, andthereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissionsof greenhouse gases could have an adverse effect on our business, financial condition, and results of operations. Finally, it should benoted that some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produceclimate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and otherclimatic events. If any such effects were to occur, they could have an adverse effect on our financial 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 46 and 51 percent of ourproduction on an BOE basis in 2014 and 2013, 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 income (loss) before interest expense, other non-operating income or expense, income taxes,depreciation, depletion, amortization, and accretion, exploration expense, property impairments, non-cash stock compensation expense,derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. AdjustedEBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generallyone-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that ispresented because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysisof our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to afinancial covenant under our credit facility based on our debt to adjusted EBITDAX ratio. In addition, adjusted EBITDAX is widelyused by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in theoil and gas exploration and production industry, and many investors use the published research of industry research analysts in makinginvestment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss)from operations, net cash provided by operating activities, or profitability or liquidity measures84prepared under 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.The 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, 2014 2013 2012 (in thousands)Net income (loss) (GAAP)$666,051 $170,935 $(54,249) Interest expense98,554 89,711 63,720 Other non-operating (income) expense, net2,561 (67) (220) Income tax expense (benefit)398,648 107,676 (29,268) Depletion, depreciation, amortization, and asset retirement obligation liabilityaccretion767,532 822,872 727,877 Exploration (1)122,577 65,888 81,809 Impairment of proved properties84,480 172,641 208,923 Abandonment and impairment of unproved properties75,638 46,105 16,342 Stock-based compensation expense32,694 32,347 30,185 Derivative gain(583,264) (3,080) (55,630) Derivative settlement gain (2)12,615 22,062 44,264 Change in Net Profits Plan liability(29,849) (21,842) (28,904) (Gain) loss on divestiture activity(646) (27,974) 27,018Adjusted EBITDAX (Non-GAAP)1,647,591 1,477,274 1,031,867 Interest expense(98,554) (89,711) (63,720) Other non-operating income (expense), net(2,561) 67 220 Income tax (expense) benefit(398,648) (107,676) 29,268 Exploration (1)(122,577) (65,888) (81,809) Exploratory dry hole expense44,427 5,846 20,861 Amortization of debt discount and deferred financing costs6,146 5,390 6,769 Deferred income taxes397,780 105,555 (29,638) Plugging and abandonment(8,796) (9,946) (2,856) Other, net1,069 2,775 527 Changes in current assets and liabilities(9,302) 14,828 10,480Net cash provided by operating activities (GAAP)$1,456,575 $1,338,514 $921,969____________________________________________(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.(2)Derivative settlement gain is reported in the derivative cash settlements line item on the accompanying statements of cash flows within net cash providedby operating activities with the change in accrued settlements between years being reported in change in accounts receivable and change in accountspayable and accrued expenses line items.85ITEM 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.86ITEM 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, 2014,and 2013, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows forthe years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to expressan 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, 2014, and 2013, and the consolidated results of its operations and its cash flowsfor the years then ended, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), SMEnergy Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and ourreport dated February 25, 2015, expressed an unqualified opinion thereon./s/ Ernst & Young LLPDenver, ColoradoFebruary 25, 201587REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and Stockholders of SM Energy Company and SubsidiariesDenver, Colorado We have audited the accompanying consolidated statements of operations, comprehensive income (loss), stockholders’ equity, andcash flows of SM Energy Company and subsidiaries (the “Company”) for the year ended December 31, 2012. These financialstatements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements 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 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 audit provides a reasonable basis for our opinion.In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows ofSM Energy Company and subsidiaries for the year ended December 31, 2012, in conformity with accounting principles generallyaccepted in the United States of America./s/ DELOITTE & TOUCHE LLPDenver, ColoradoFebruary 21, 201388SM ENERGY COMPANY AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands, except share amounts) December 31, 2014 2013 ASSETS Current assets: Cash and cash equivalents$120 $282,248Accounts receivable (note 2)322,630 318,371Derivative asset402,668 21,559Deferred income taxes— 10,749Prepaid expenses and other19,625 14,574Total current assets745,043 647,501 Property and equipment (successful efforts method): Proved oil and gas properties7,348,436 5,637,462Less - accumulated depletion, depreciation, and amortization(3,233,012) (2,583,698)Unproved oil and gas properties532,498 271,100Wells in progress503,734 279,654Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of$22,482 and $7,390, respectively17,891 19,072Other property and equipment, net of accumulated depreciation of $37,079 and $28,775, respectively334,356 236,202Total property and equipment, net5,503,903 3,859,792 Noncurrent assets: Derivative asset189,540 30,951Restricted cash— 96,713Other noncurrent assets78,214 70,208Total other noncurrent assets267,754 197,872Total Assets$6,516,700 $4,705,165 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued expenses (note 2)$640,684 $606,751Derivative liability— 26,380Deferred tax liability142,976 —Other current liabilities1,000 6,000Total current liabilities784,660 639,131 Noncurrent liabilities: Revolving credit facility166,000 —Senior Notes (note 5)2,200,000 1,600,000Asset retirement obligation120,867 118,692Net Profits Plan liability27,136 56,985Deferred income taxes891,681 650,125Derivative liability70 4,640Other noncurrent liabilities39,631 28,771Total noncurrent liabilities3,445,385 2,459,213 Commitments and contingencies (note 6) Stockholders' equity: Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 67,463,060 and 67,078,853shares outstanding, respectively; net of treasury shares: 67,463,060 and 67,056,441, respectively675 671Additional paid-in capital283,295 257,720Treasury stock, at cost: zero and 22,412 shares, respectively— (823)Retained earnings2,013,997 1,354,669Accumulated other comprehensive loss(11,312) (5,416)Total stockholders' equity2,286,655 1,606,821Total Liabilities and Stockholders' Equity$6,516,700 $4,705,165The 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, 2014 2013 2012Operating revenues: Oil, gas, and NGL production revenue$2,481,544 $2,199,550 $1,473,868Gain (loss) on divestiture activity646 27,974 (27,018)Marketed gas system revenue24,897 60,039 52,808Other operating revenues15,220 5,811 5,444Total operating revenues and other income2,522,307 2,293,374 1,505,102Operating expenses: Oil, gas, and NGL production expense715,878 597,045 391,872Depletion, depreciation, amortization, and asset retirement obligation liabilityaccretion767,532 822,872 727,877Exploration129,857 74,104 90,248Impairment of proved properties84,480 172,641 208,923Abandonment and impairment of unproved properties75,638 46,105 16,342General and administrative167,103 149,551 119,815Change in Net Profits Plan liability(29,849) (21,842) (28,904)Derivative gain(583,264) (3,080) (55,630)Marketed gas system expense24,460 57,647 47,583Other operating expenses4,658 30,076 6,993Total operating expenses1,356,493 1,925,119 1,525,119Income (loss) from operations1,165,814 368,255 (20,017)Non-operating income (expense): Other, net(2,561) 67 220Interest expense(98,554) (89,711) (63,720)Income (loss) before income taxes1,064,699 278,611 (83,517)Income tax (expense) benefit(398,648) (107,676) 29,268Net income (loss)$666,051 $170,935 $(54,249)Basic weighted-average common shares outstanding67,230 66,615 65,138Diluted weighted-average common shares outstanding68,044 67,998 65,138Basic net income (loss) per common share$9.91 $2.57 $(0.83)Diluted net income (loss) per common share$9.79 $2.51 $(0.83)The 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, 2014 2013 2012Net income (loss)$666,051 $170,935 $(54,249)Other comprehensive income (loss), net of tax: Reclassification to earnings (1)— 1,115 (2,264) Pension liability adjustment (2)(5,896) 2,483 (2,470)Total other comprehensive income (loss), net of tax(5,896) 3,598 (4,734)Total comprehensive income (loss)$660,155 $174,533 $(58,983)(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, 201264,145,482 $641 $216,966 (81,067) $(1,544) $1,251,157 $(4,280) $1,462,940Net loss— — — — — (54,249) — (54,249)Other comprehensive loss— — — — — — (4,734) (4,734)Cash dividends, $ 0.10 per share— — — — — (6,511) — (6,511)Issuance of common stock underEmployee Stock Purchase Plan66,485 1 2,775 — — — — 2,776Issuance of common stock uponvesting of RSUs and settlement ofPSUs, net of shares used for taxwithholdings929,375 9 (21,631) — — — — (21,622)Issuance of common stock uponstock option exercises240,368 2 3,038 — — — — 3,040Conversion of 3.50% SeniorConvertible Notes to common stock,including income tax benefit ofconversion864,106 9 2,632 — — — — 2,641Stock-based compensation expense— — 29,862 30,486 323 — — 30,185Balances, December 31, 201266,245,816 $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 income— — — — — — (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) $2,286,655The 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, 2014 2013 2012Cash flows from operating activities: Net income (loss)$666,051 $170,935 $(54,249)Adjustments to reconcile net income (loss) to net cash provided by operating activities: (Gain) loss on divestiture activity(646) (27,974) 27,018Depletion, depreciation, amortization, and asset retirement obligation liability accretion767,532 822,872 727,877Exploratory dry hole expense44,427 5,846 20,861Impairment of proved properties84,480 172,641 208,923Abandonment and impairment of unproved properties75,638 46,105 16,342Stock-based compensation expense32,694 32,347 30,185Change in Net Profits Plan liability(29,849) (21,842) (28,904)Derivative gain(583,264) (3,080) (55,630)Derivative cash settlements(28,419) 22,062 44,264Amortization of debt discount and deferred financing costs6,146 5,390 6,769Deferred income taxes397,780 105,555 (29,638)Plugging and abandonment(8,796) (9,946) (2,856)Other, net1,069 2,775 527Changes in current assets and liabilities: Accounts receivable24,088 (78,494) (21,389)Prepaid expenses and other(1,822) 98 733Accounts payable and accrued expenses9,466 93,224 31,136Net cash provided by operating activities1,456,575 1,338,514 921,969 Cash flows from investing activities: Net proceeds from sale of oil and gas properties43,858 424,849 55,375Capital expenditures(1,974,798) (1,553,536) (1,507,828)Acquisition of proved and unproved oil and gas properties(544,553) (61,603) (5,773)Other, net(3,256) (2,613) 893Net cash used in investing activities(2,478,749) (1,192,903) (1,457,333) Cash flows from financing activities: Proceeds from credit facility1,285,500 1,203,000 1,609,000Repayment of credit facility(1,119,500) (1,543,000) (1,269,000)Debt issuance costs related to credit facility(3,388) (3,444) —Net proceeds from Senior Notes589,991 490,185 392,138Repayment of 3.50% Senior Convertible Notes— — (287,500)Proceeds from sale of common stock4,877 6,858 5,816Dividends paid(6,723) (6,663) (6,511)Net share settlement from issuance of stock awards(10,624) (16,220) (21,622)Other, net(87) (5) (225)Net cash provided by financing activities740,046 130,711 422,096 Net change in cash and cash equivalents(282,128) 276,322 (113,268)Cash and cash equivalents at beginning of period282,248 5,926 119,194Cash and cash equivalents at end of period$120 $282,248 $5,926The 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, 2014 2013 2012 (in thousands)Cash paid for interest, net of capitalized interest$89,145 $70,702 $51,328 Net cash paid (refunded) for income taxes$1,936 $(204) $(1,389)As of December 31, 2014, 2013, and 2012, $357.2 million, $217.8 million, and $262.8 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 cashused in investing activities in the periods during which the payables are settled.During the second quarter of 2014, the Company exchanged properties in its Rocky Mountain region with a fair value of $6.2 million. During thethird quarter of 2013, the Company exchanged properties in its Rocky Mountain region with a fair value of $25.0 million. The cash consideration exchangedat the respective closings for agreed upon adjustments is reflected in the acquisition of proved and unproved oil and gas properties line item in theconsolidated 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, 2014, 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. The Company’s refundable income taxes are combined and presented in the prepaid expenses and other financialstatement line item within the accompanying balance sheets. The Company’s land and materials inventory are combined and presentedin the other property and equipment, net of accumulated depreciation financial statement line item within the accompanying balancesheets. Lastly, the asset retirement obligation associated with oil and gas properties held for sale is no longer separately presented and ispresented in the asset retirement obligation financial statement line item within the accompanying balance sheets. Within theaccompanying consolidated statements of operations (“accompanying statements of operations”), the Company’s realized hedge gain(loss) is combined and presented in the other operating revenues financial statement line item. In the accompanying consolidatedstatements of cash flows (“accompanying statements of cash flows”) in cash flows from operating activities, refundable income taxes isnow combined and presented with prepaid expenses and other. Additionally, receipts from restricted cash related to any like-kindexchanges under Section 1031 of the Internal Revenue Code are now combined and presented in the other, net financial statement lineitem within net cash used in investing activities on the accompanying statements of cash flows.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, asset retirement obligations, and the Net Profits Plan liability, each of whichrepresents a significant component 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.95Restricted CashThe Company has no restricted cash at December 31, 2014. The restricted cash balance at December 31, 2013, mainlyconsisted of cash payments that were contractually restricted to be used solely for development of long-term capital assets pursuant tothe Company’s Acquisition and Development Agreement with Mitsui and accordingly classified as non-current assets. Please refer toNote 12 - Acquisition and Development Agreement for additional information.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. As of December 31,2014 and 2013, the Company had no allowance for doubtful accounts recorded.Concentration 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 2014, theCompany had one major customer, which accounted for approximately 19 percent of total production revenue, which is discussed inthe next paragraph. In 2014, the Company also sold to four entities that are under common ownership. In aggregate, these four entitiesaccounted for approximately 14 percent of total production revenues in 2014, however, none of these entities individually accountedfor greater than 10 percent of total production revenue. During 2013, the Company had three major customers, which accounted forapproximately 26 percent, 16 percent, and 12 percent, respectively, of total production revenue. During 2012, the Company had twomajor customers, which accounted for approximately 21 percent and 13 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 through-put commitments for up to 10 years pursuant toeach contract. While the Company’s joint venture partner is the first purchaser under these contracts, accounting for 19 percent of totalproduction revenue in 2014, the Company also shares with them the risk of non-performance by their counterparty purchasers. Severalof the Company’s joint venture partner’s counterparty purchasers under these contracts are also direct purchasers of products producedby the Company.The Company’s policy is to use the commodity affiliates of the lenders under its credit facility as its derivative counterparties.Additionally, the Company’s policy is that the counterparty must have investment grade senior unsecured debt ratings. Each of theCompany’s nine counterparties currently meet both of these requirements.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.96Oil 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, 2014, and 2013, the estimatedsalvage value of the Company’s equipment was $50.8 million and $57.5 million, respectively.Assets 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 net book value or fair value less the cost to sell. For additional discussion on assetsheld for sale, please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale.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, 2014, and 2013, the Company has capitalized approximately $35.0million and $11.2 million, respectively, related to the ongoing development and implementation of accounting and operationalsoftware. Derivative Financial InstrumentsThe Company seeks to manage or reduce commodity price risk on 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.97Net 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.Asset 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 completed or acquired. The increase in carrying value is included in proved oil and gasproperties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs andrecognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of therespective oil and 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, NYMEX, OPIS, and local spot market prices, quality andtransportation differentials, and other factors as the basis for these estimates. The Company uses the sales method of accounting for gasrevenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to theCompany’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 developed reserves and risk adjusted proved undeveloped, probable, and possible reserves using a discountrate and price forecasts that management believes are representative of current market conditions. The prices for oil and gas areforecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is usedfor each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as themarket is actively trading, after which a flat terminal price is used. Future operating costs are also98adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determinesthat either the property will not be developed or the carrying value is not realizable.The Company recorded $84.5 million, $172.6 million, and $208.9 million, of proved property impairment expense for the yearsended December 31, 2014, 2013, and 2012, respectively. The impairments of proved properties in 2014 were 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 resulted from the write-down of certainMississippian limestone assets in the Company’s Permian region due to negative engineering revisions, write-downs related to Olmosinterval, dry gas assets in the South Texas & Gulf Coast region as a result of a plugging and abandonment program, and write-downs ofcertain underperforming assets due to the Company’s decision to no longer pursue the development of those assets. The impairments in2012 were a result of the Company’s write-down of Wolfberry assets in its Permian region due to negative engineering revisions andthe Company’s Haynesville shale assets as a result of low natural gas prices.For the years ended December 31, 2014, 2013, and 2012, the Company recorded expense related to the abandonment andimpairment of unproved properties of $75.6 million, $46.1 million, and $16.3 million, respectively. The Company’s abandonment andimpairment of unproved properties expense in 2014 was due to acreage the Company no longer intended to develop as a result ofexploration and delineation activities and the recent decline in commodity prices. The Company’s abandonment and impairment ofunproved properties expense in 2013 was mostly related to acreage the Company no longer intended to develop in its Permian region.The Company’s abandonment and impairment of unproved properties expense in 2012 related to acreage that the Company no longerintended to develop in its Rocky Mountain region.Sales of Proved and Unproved PropertiesThe partial sale of proved property within an existing field is accounted for as normal retirement and no 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 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 gain on divestiture activity is recognized to the extent that the sales priceexceeds the carrying amount of the unproved property. A 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 – Acquisitions,Divestitures, and Assets Held for Sale.Stock-Based CompensationAt December 31, 2014, 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.99Income 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.Earnings 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 in-the-money outstanding stock options, unvested RSUs, contingent PSUs, and shares into which the 3.50%Senior Convertible Notes were convertible. When there is a loss from continuing operations, as was the case for the year endedDecember 31, 2012, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of dilutedearnings 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 Incentive Compensation Plan.The Company called for redemption of its 3.50% Senior Convertible Notes on April 2, 2012, after which the majority of theholders of the outstanding 3.50% Senior Convertible Notes elected to convert their notes. The Company issued 864,106 commonshares upon conversion, and these shares were included in the calculation of basic weighted-average common shares outstanding forthe year ended December 31, 2012, and all subsequent years the shares remain outstanding. Please refer to Note 5 - Long-term Debt foradditional discussion. Prior to calling the 3.50% Senior Convertible Notes for redemption, the Company’s notes had a net-sharesettlement right giving the Company the option to irrevocably elect, by notice to the trustee under the indenture for the notes, to settlethe Company’s obligation, in the event that holders of the notes elected to convert all or a portion of their notes, by delivering cash inan amount equal to each $1,000 principal amount of notes surrendered for conversion and, if applicable, at the Company’s option,shares of common stock or cash, or any combination of common stock and cash, for the amount of conversion value in excess of theprincipal amount. Prior to the settlement of the Company’s 3.50% Senior Convertible Notes, potentially dilutive shares associated withthe conversion feature were accounted for using the treasury stock method when shares of the Company’s common stock traded at anaverage closing price that exceeded the $54.42 conversion price. Shares of the Company’s common stock traded at an average closingprice exceeding the conversion price and were included on an adjusted weighted basis for the portion of the year ended December 31,2012, for which they were outstanding. The Company recorded a loss from continuing operations for the year ended December 31,2012, and therefore, the shares into which the 3.50% Senior Convertible Notes were convertible were anti-dilutive and excluded fromthe calculation of diluted earnings per share, as shown in the table below.The treasury stock method is used to measure the dilutive impact of in-the-money stock options, unvested RSUs, contingentPSUs, and the 3.50% Senior Convertible Notes.100The following table details the weighted-average dilutive and anti-dilutive securities related to stock options, RSUs, PSUs, andthe 3.50% Senior Convertible Notes for the years presented: For the Years Ended December 31, 2014 2013 2012 (in thousands)Dilutive814 1,383 —Anti-dilutive— — 2,102The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2014 2013 2012 (in thousands, except per share amounts)Net income (loss)$666,051 $170,935 $(54,249)Basic weighted-average common shares outstanding67,230 66,615 65,138Add: dilutive effect of stock options, unvested RSUs, and contingentPSUs814 1,383 —Add: dilutive effect of 3.50% Senior Convertible Notes (1)— — —Diluted weighted-average common shares outstanding68,044 67,998 65,138Basic net income (loss) per common share$9.91 $2.57 $(0.83)Diluted net income (loss) per common share$9.79 $2.51 $(0.83)____________________________________________(1) For the year ended December 31, 2012, the shares into which the 3.50% Senior Convertible Notes were convertible were anti-dilutive and excluded fromthe 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 are reported as separatecomponents of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in theaccompanying consolidated statements of comprehensive income (loss).101The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Derivative Adjustments Pension LiabilityAdjustments (in thousands)For the year ended December 31, 2012 Net actuarial loss $(4,680)Reclassification to earnings$(3,865) 771Tax benefit1,601 1,439Loss, net of tax$(2,264) $(2,470)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)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$166.0 million of outstanding loans under its credit facility as of December 31, 2014. The Company had no borrowings outstandingunder its credit facility as of December 31, 2013. The Company’s Senior Notes are recorded at cost and the respective fair values aredisclosed in Note 11 - Fair Value Measurements. The Company has derivative financial instruments that are recorded at fair value.Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of theamounts 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 and all of the Company’soperations are conducted entirely within the United States. The Company reports as a single industry segment. The Company’s gasmarketing function provides mostly internal services and acts as the first purchaser of natural gas and natural gas liquids produced bythe Company in certain cases. The Company considers its marketing function as ancillary to its oil and gas producing activities. Theamount of income these operations generate from marketing gas produced by third parties is not material to the Company’s results ofoperations, and segmentation of such activity would not provide a better understanding of the Company’s performance. However, grossrevenue and expense related to marketing activities for gas produced by third parties are presented in the marketed gas system revenueand marketed gas system expense line items in the accompanying statements of operations.102Off-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 2014 or 2013.Recently Issued Accounting StandardsEffective October 1, 2014, the Company early adopted, on a prospective basis, Financial Accounting Standards Board(“FASB”) Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals ofComponents of an Entity.” This ASU changed the criteria for reporting discontinued operations while enhancing disclosures in thisarea. There was no impact to the Company’s financial statements or disclosures from the early adoption of this standard.In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts withcustomers. This guidance is to be applied using a retrospective method or a modified retrospective method, as outlined in the guidance,and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Earlyapplication is not permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on theCompany’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.In January 2015, the FASB issued new authoritative accounting guidance that simplifies income statement presentation byeliminating extraordinary items from GAAP. This guidance is to be applied either prospectively or retrospectively and is effective forannual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permittedprovided the guidance is applied from the beginning of the annual year of adoption. The Company is currently evaluating theprovisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.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 retrospective method or a modified retrospective method, as outlined in the guidance,and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Earlyapplication is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on theCompany’s financial statements and disclosures. There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Companyas of December 31, 2014, and through the 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, 20142013 (in thousands)Accrued oil, gas, and NGL production revenue$180,250 $228,169Amounts due from joint interest owners58,347 37,517Accrued derivative settlements39,811 770State severance tax refunds24,394 29,213Other19,828 22,702Total accounts receivable$322,630 $318,371Accounts payable and accrued expenses are comprised of the following: As of December 31, 2014 2013 (in thousands)Accrued capital expenditures$357,156 $217,820Revenue and severance tax payable63,779 87,852Accrued lease operating expense34,822 29,296Accrued property taxes15,059 10,401Joint owner advances152 96,636Accrued compensation56,279 71,466Accrued interest40,786 40,027Other72,651 53,253Total accounts payable and accrued expenses$640,684 $606,751Note 3 – Acquisitions, Divestitures, and Assets Held for Sale2014 Acquisition Activity•Gooseneck Property Acquisitions. On September 24, 2014, the Company acquired approximately 61,000 net acres of provedand unproved oil and gas properties in its Gooseneck area in North Dakota, along with related equipment, contracts, records,and other assets. Total cash consideration paid by the Company was $325.2 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.It was 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 preliminary adjusted purchase price to theacquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Theseacquisitions are subject to normal post-closing adjustments, which are expected to be completed in the first half of 2015. Referto Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair valueof acquired properties.104 As of September 24,2014 As of October 15,2014Purchase Price(in thousands)Cash consideration$325,230 $84,836 Fair value of assets acquired: Proved oil and gas properties$203,493 $54,360Unproved oil and gas properties126,622 29,469Total fair value of oil and gas propertiesacquired330,115 83,829 Working capital(2,772) 2,625Asset retirement obligation(2,113) (1,618)Total fair value of net assets acquired$325,230 $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 in multiple transactions for approximately $134.5million in total cash consideration, plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountainregion. These acquisitions are subject to normal post-closing adjustments, which are expected to be completed in early 2015.2014 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 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 are reflected as a loss on divestiture activity in the accompanying statements ofoperations, and mostly offset the gain on the Rocky Mountain divestiture discussed above. Please refer to Assets Held for Sale belowfor further discussion.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 net gain on these divestitures was $25.3 million. A portion of one transaction was structured toqualify 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 proceeds for this divestiture 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, 2013.1052012 Divestiture ActivityIn 2012, the Company divested of various non-strategic properties located in its Rocky Mountain andMid-Continent regions. Final divestiture proceeds were $57.9 million and the final net gain on these divestitures was $7.4 million.During 2012, the Company reclassified a portion of the assets previously held for sale to assets held and used, as the assets wereno longer being actively marketed. The assets were measured at the lower of the carrying value of the assets before being classified asheld for sale, adjusted for any DD&A that would have been recognized had the assets been continuously held and used, or the fairvalue of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, the Company recognized$1.7 million of DD&A expense and a $33.9 million loss on unsuccessful sale of properties, which is included in gain (loss) ondivestiture activity in the accompanying statements of operations.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.Subsequent changes to the estimated fair value less the costs to sell will impact the measurement of assets held for sale for which fairvalue less costs to sell is determined to be less than the carrying value of the assets.As of December 31, 2014, the accompanying balance sheets present $17.9 million of assets held for sale, net of accumulatedDD&A expense. There is a corresponding asset retirement obligation liability of $438,000 for assets held for sale included in the assetretirement obligation financial statement line item. Assets held for sale are recorded at the lesser of their respective carrying value or fairvalue less estimated costs to sell. Certain assets classified as held for sale during 2014 were written down to fair value less estimatedcosts to sell, which was recorded in the gain (loss) on divestiture activity line item in the accompanying statements of operations.Subsequent to December 31, 2014, the Company began marketing its assets in the Arkoma Basin of Oklahoma and in theArklatex area of east Texas and northern Louisiana and expects the assets to be sold during 2015. These assets did not meet therequirements to be classified as held for sale as of December 31, 2014.The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accountingunder financial statement presentation authoritative guidance.106Note 4 – Income TaxesThe provision for income taxes consists of the following: For the Years Ended December 31, 2014 2013 2012 (in thousands)Current portion of income tax expense Federal $— $— $—State 868 2,121 370Deferred portion of income tax expense (benefit) 397,780 105,555 (29,638)Total income tax expense (benefit) $398,648 $107,676 $(29,268)Effective tax rate 37.4% 38.6% 35.0%The Company reduces its income tax payable to reflect employee stock option exercises. There was no excess income taxbenefit associated with stock awards in 2014, 2013, or 2012.The components of the net deferred income tax liabilities are as follows: As of December 31, 2014 2013 (in thousands)Deferred tax liabilities: Oil and gas properties $1,029,424 $768,463Derivative asset 220,437 9,529Other 4,475 1,245Total deferred tax liabilities 1,254,336 779,237Deferred tax assets: Federal and state tax net operating loss carryovers 184,447 91,788Stock compensation 16,763 18,820Other long-term liabilities 16,301 13,341Net Profits Plan liability 9,414 20,913Total deferred tax assets 226,925 144,862Valuation allowance (7,246) (5,001)Net deferred tax assets 219,679 139,861Total net deferred tax liabilities 1,034,657 639,376Less: current deferred income tax liabilities (152,082) (172)Add: current deferred income tax assets 9,106 10,921Non-current net deferred tax liabilities $891,681 $650,125Current federal income tax refundable $4,734 $4,630Current state income tax refundable $— $—Current state income tax payable $25 $1,460At December 31, 2014, the Company estimated its federal net operating loss carryforward at $626.2 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 $284.8 million that expire between 2015and 2035 and it has federal R&D credit carryforwards of $3.5 million that expire between 2028 and 2032. The Company’s valuationallowance relates to charitable contribution carryforwards, state net operating loss carryforwards, and state tax credits, which the107Company anticipates will expire before they can be utilized. The change in the valuation allowance from 2013 to 2014 primarilyreflects a change in the Company’s position regarding anticipated utilization of cumulative state net operating losses.Federal 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,percentage depletion, R&D credits, and other permanent differences, as follows: For the Years Ended December 31, 2014 2013 2012 (in thousands)Federal statutory tax expense (benefit)$372,644 $97,514 $(29,231)Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit)21,350 9,400 (992)Research and development credit— — (970)Change in valuation allowance2,245 (314) 1,524Other2,409 1,076 401Income tax expense (benefit)$398,648 $107,676 $(29,268)Acquisitions, 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. The Internal Revenue Service (“IRS”) initiated an audit in the first quarter of 2012 related to an R&D tax credit claimed by theCompany for the 2007 through 2010 tax years. On April 23, 2013, the IRS issued a Notice of Proposed Adjustment disallowing $4.6million of an R&D tax credit claimed for open tax years during the audit period. During the third quarter ended September 30, 2014,the Company successfully reached an agreement with the IRS Appeals Office (“Appeals”) related to the claimed R&D credit andrecorded an immaterial adjustment. In the fourth quarter of 2014, Appeals returned the case to the Examination Team for final review.At December 31, 2014, the Company was waiting on final review and evaluating the basis for claiming the R&D credit for the 2012and 2013 tax years. Subsequent to year-end, the Company concluded its evaluation, and preliminary estimates indicate it may beentitled to claim approximately $2.4 million of additional net R&D credit. The Company anticipates finalizing the amounts and filingamended returns in the first quarter of 2015. The tables above do not include the impact of the estimated amount.On September 13, 2013, the United States Department of the Treasury and IRS issued final and re-proposed tangible propertyregulations effective for tax years beginning January 1, 2014. The Company has determined it is materially compliant with therequirements of these regulations as of December 31, 2014.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, 2014, theCompany estimates the range of reasonably possible change in 2015 to the table below could be from zero to $1.2 million.108The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2014 2013 2012 (in thousands)Beginning balance$2,358 $2,278 $1,961Additions for tax positions of prior years140 80 317Settlements(916) — —Ending balance$1,582 $2,358 $2,278Note 5 – Long-term DebtRevolving Credit FacilityThe Company and its lenders entered into a Second Amendment to the Fifth Amended and Restated Credit Agreement onDecember 10, 2014. The Company incurred approximately $3.4 million in deferred financing costs associated with the amendment andextension of this credit facility. As amended, the Company’s credit facility has a maximum loan amount of $2.5 billion, currentaggregate lender commitments of $1.5 billion, and a maturity date of December 10, 2019. The borrowing base is subject to regularsemi-annual redeterminations. On October 6, 2014, the lending group redetermined the Company's borrowing base under the creditfacility and increased it from $2.2 billion to $2.4 billion. The December 10, 2014 amendment to the credit facility specified that theborrowing base was not reduced by the issuance of the 2022 Notes and will remain at $2.4 billion until the next redetermination date,scheduled for April 1, 2015. The borrowing base redetermination process under the credit facility considers the value of the Company’sproved oil and gas properties, as determined by the lender group. Borrowings under the facility are secured by at least 75 percent of thevalue of the Company’s proved oil and gas properties. The Company must comply with certain financial and non-financial covenants under the terms of its credit facility agreement,including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to adjustedEBITDAX, as defined by the Company’s credit agreement as the ratio of debt to 12-month trailing adjusted EBITDAX, of less than 4.0and an adjusted current ratio, as defined by the Company’s credit agreement, of no less than 1.0. The Company was in compliancewith all financial and non-financial covenants under the credit facility as of December 31, 2014, and through the filing date of thisreport. 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%109The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity underthe Company's credit facility as of February 18, 2015, December 31, 2014, and December 31, 2013: As of February 18, 2015 As of December 31, 2014 As of December 31, 2013 (in thousands)Credit facility balance$341,000 $166,000 $—Letters of credit (1)$808 $808 $808Available borrowing capacity$1,158,192 $1,333,192 $1,299,192____________________________________________(1) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.Senior NotesThe Senior Notes line on the accompanying balance sheets, as of December 31, 2014, and 2013, consisted of the following: As of December 31, 2014 2013 (in thousands)2019 Notes$350,000 $350,0002021 Notes350,000 350,0002022 Notes600,000 —2023 Notes400,000 400,0002024 Notes500,000 500,000Total Senior Notes$2,200,000 $1,600,000The 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 indenture governing the Senior Notes that limit theCompany’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; provided,however, that the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company wasin compliance with all covenants under its Senior Notes as of December 31, 2014, and through the filing date of this report.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. The netproceeds were used to repay outstanding borrowings under the Company’s credit facility and for general corporate purposes.Prior to November 15, 2017, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principalamount of the 2022 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.125% of the principalamount thereof, plus accrued and unpaid interest. The Company may also redeem the 2022 Notes, in whole or in part, at any time priorto November 15, 2018, at a redemption price equal to 100 percent of the principal amount of the 2022 Notes to be redeemed, plus aspecified make-whole premium and accrued and unpaid interest to the applicable redemption date. 110On or after November 15, 2018, the Company may also redeem all or, from time to time, a portion of the 2022 Notes at theredemption prices set forth below, during the twelve-month period beginning on November 15 of each applicable year, expressed as apercentage of the principal amount redeemed, plus accrued and unpaid interest:2018103.063%2019101.531%2020 and thereafter100.000%Additionally, on November 17, 2014, the Company entered into a registration rights agreement that provides holders of the2022 Notes certain registration rights under the Securities Act. Pursuant to the registration rights agreement, the Company is required tofile an exchange offer registration statement with the SEC with respect to its offer to exchange the 2022 Notes for substantially identicalnotes that are registered under the Securities Act. Under certain circumstances, the Company has agreed to file a shelf registrationstatement relating to the resale of the 2022 Notes in lieu of a registered exchange offer. If the registration statement related to theexchange offer is not declared effective on or before November 17, 2015, or if the shelf registration statement, if required, is notdeclared effective within the time periods specified in the registration rights agreement, the Company has agreed to pay additionalinterest with respect to the 2022 Notes in an amount not to exceed one percent of the principal amount of the 2022 Notes until theexchange offer is completed or the shelf registration statement is declared effective.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. The net proceeds were used toreduce the Company’s outstanding credit facility balance.Prior to July 15, 2016, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principalamount of the 2024 Notes with the net cash proceeds of certain equity offerings at a redemption price of 105% of the principal amountthereof, plus accrued and unpaid interest. The Company may also redeem the 2024 Notes, in whole or in part, at any time prior toJuly 15, 2018, at a redemption price equal to 100 percent of the principal amount of the 2024 Notes to be redeemed, plus a specifiedmake-whole premium and accrued and unpaid interest to the applicable redemption date. On or after July 15, 2018, the Company may also redeem all or, from time to time, a portion of the 2024 Notes at theredemption prices set forth below, during the twelve-month period beginning on July 15 of each applicable year, expressed as apercentage of the principal amount redeemed, plus accrued and unpaid interest:2018102.500%2019101.677%2020100.833%2021 and thereafter100.000%Additionally, on May 20, 2013, the Company entered into a registration rights agreement that provides holders of the 2024Notes certain registration rights under the Securities Act. The Company closed its offer to exchange its 2024 Notes for notes registeredunder the Securities Act on June 25, 2014.1112023 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. The net proceeds were usedto reduce the Company’s outstanding credit facility balance.Prior to July 1, 2015, the Company may redeem, on one or more occasions, up to 35 percent of the aggregate principal amountof the 2023 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.5% of the principal amountthereof, plus accrued and unpaid interest. The Company may also redeem the 2023 Notes, in whole or in part, at any time prior toJuly 1, 2017, at a redemption price equal to 100 percent of the principal amount of the 2023 Notes to be redeemed, plus a specifiedmake-whole premium and accrued and unpaid interest to the applicable redemption date.On or after July 1, 2017, the Company may also redeem all or, from time to time, a portion of the 2023 Notes at the redemptionprices set forth below, during the twelve-month period beginning on July 1 of each applicable year, expressed as a percentage of theprincipal amount redeemed, plus accrued and unpaid interest:2017103.250%2018102.167%2019101.083%2020 and thereafter100.000%Additionally, on June 29, 2012, the Company entered into a registration rights agreement that provides holders of the 2023Notes certain registration rights under the Securities Act. The Company satisfied its obligations to exchange its outstanding $400.0million of its 2023 Notes for notes registered under the Securities Act on October 30, 2012.2021 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. The net proceedswere used for general corporate purposes and to reduce the Company’s outstanding credit facility balance.The Company may redeem the 2021 Notes, in whole or in part, at any time prior to November 15, 2016, at a redemption priceequal to 100 percent of the principal amount, plus a specified make-whole premium and accrued and unpaid interest. The Company may also redeem all or, from time to time, a portion of the 2021 Notes on or after November 15, 2016, at theprices set forth below, during the twelve-month period beginning on November 15 of the applicable year, expressed as a percentage ofthe principal amount redeemed, plus accrued and unpaid interest:2016103.250%2017102.167%2018101.083%2019 and thereafter100.000%112Additionally, on November 8, 2011, the Company entered into a registration rights agreement that provides holders of the 2021Notes certain registration rights for the 2021 Notes under the Securities Act. The Company satisfied its obligations to exchange itsoutstanding $350.0 million of its 2021 Notes for notes registered under the Securities Act on March 7, 2012.2019 NotesOn February 7, 2011, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2019. The2019 Notes were issued at par and mature on February 15, 2019. The Company received net proceeds of $341.1 million after deductingfees of $8.9 million, which are being amortized as deferred financing costs over the life of the 2019 Notes. The net proceeds were usedto repay borrowings under the Company’s credit facility, to fund the Company’s ongoing capital expenditure program, and for generalcorporate purposes.The Company may redeem all or, from time to time, a portion of the 2019 Notes on or after February 15, 2015, at the prices setforth in the table below, during the twelve-month period beginning on February 15 of the applicable year, expressed as a percentage ofthe principal amount redeemed, plus accrued and unpaid interest:2015103.313%2016101.656%2017 and thereafter100.000%Additionally, on February 7, 2011, the Company entered into a registration rights agreement that provides holders of the 2019Notes certain registration rights for the 2019 Notes under the Securities Act. The Company satisfied its obligations to exchange itsoutstanding $350.0 million of its 2019 Notes for notes registered under the Securities Act on January 11, 2012.3.50% Senior Convertible NotesOn April 2, 2012, the Company called for redemption all of its outstanding 3.50% Senior Convertible Notes. The call forredemption resulted in holders of $281.3 million aggregate principal amount electing to convert their notes. The Company settled theprincipal amount of all converted 3.50% Senior Convertible Notes in cash and settled the excess conversion value by issuing 864,106shares of its common stock. The Company redeemed the remaining $6.2 million of aggregate principal amount of notes that were notconverted on the redemption date at par plus accrued interest in cash. The Company used funds borrowed under its credit facility to paythe cash portion of the settlement.Capitalized InterestCapitalized interest costs for the Company for the years ended December 31, 2014, 2013, and 2012, were $16.2 million, $11.0million, and $12.1 million, respectively.113Note 6 – Commitments and ContingenciesCommitmentsThe Company has entered into various agreements, which include drilling rig contracts of $116.1 million, gathering, processing,and transportation through-put commitments of $939.4 million, office leases, including maintenance, of $69.3 million, and othermiscellaneous contracts and leases of $11.7 million. The annual minimum payments for the next five years and total minimumpayments thereafter are presented below:Years Ending December 31, (in thousands)2015 $224,8972016 147,8962017 118,3202018 128,8662019 132,920Thereafter 383,619Total $1,136,518Drilling rig contractsThe Company has multiple long-term drilling rig contracts. Early termination of these rig contracts as of December 31, 2014,would result in termination penalties of $75.8 million, which would be in lieu of paying the remaining drilling commitments of $116.1million included in the table above.Transportation commitments The Company has gathering, processing, and transportation through-put commitments with various third parties that requiredelivery of a minimum amount of 1,411 Bcf of natural gas and 48 MMBbl of crude oil. These contracts expire at various dates through2028 and the total amount of the commitment is approximately $939.4 million. The Company will be required to make periodicdeficiency payments for any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volumecommitment for natural gas is projected, the Company has rights under certain contracts to arrange for third party gas to be delivered,and such volumes would count toward its minimum volume commitment. As of the filing date of this report, the Company does notexpect to incur any material shortfalls.Office leasesThe Company leases office space under various operating leases with terms extending as far as 2026. Rent expense for yearsended December 31, 2014, 2013, and 2012, was $6.5 million, $5.7 million, and $5.4 million, respectively. The Company also leasesoffice 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.114Note 7 – Compensation PlansCash Bonus PlanThe Company has a cash bonus plan based on a performance measurement framework whereby selected eligible employeeparticipants may be awarded an annual cash bonus. As the plan is currently administered, any awards under the plan are based onCompany and regional performance and are then further refined by individual performance. The Company accrues cash bonus expensebased upon the Company’s current year performance. Included in general and administrative expense, lease operating expense, andexploration expense in the accompanying statements of operations are $37.8 million, $41.8 million, and $16.3 million of cash bonusexpense related to the specific performance years ended December 31, 2014, 2013, and 2012, respectively.Equity 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, 2014, 3.6 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, a 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 StockOption Plan, both predecessors to the Equity Plan.Performance Share Units Under the Equity Incentive Compensation PlanThe Company grants PSUs to eligible employees as a part of its equity compensation program. The PSU factor is based on theCompany’s performance after completion of a three-year performance 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. PSUs are recognizedas general and administrative and exploration expense over the vesting periods of the award.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.Total expense recorded for PSUs was $16.0 million, $16.8 million, and $18.2 million for the years ended December 31, 2014,2013, and 2012, respectively. As of December 31, 2014, there was $19.8 million of total unrecognized expense related to PSUs, whichis being amortized through 2017.115A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2014 2013 2012 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-AverageGrant-DateFair ValueNon-vested at beginning ofyear (1)572,469 $66.07 669,308 $63.91 885,894 $57.52Granted (1)202,404 $94.66 274,831 $64.13 314,853 $51.98Vested (1)(206,830) $64.79 (345,005) $60.06 (493,679) $44.72Forfeited (1)(134,383) $86.72 (26,665) $69.74 (37,760) $65.35Non-vested at end of year(1)433,660 $73.63 572,469 $66.07 669,308 $63.91____________________________________________(1)The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three-yearperformance multiplier, which ranges from zero to two.The fair value of the PSUs granted in 2014, 2013, and 2012 was $19.2 million, $17.6 million, and $16.4 million for the 2014,2013, and 2012 grants, respectively. The PSUs granted in 2013 and 2014 will remain unvested until the third anniversary date of theirissuance, at which time they will fully vest. The PSUs granted in 2012 vest 1/3 on each of the first three anniversary dates of theirissuance.The total fair value of PSUs that vested during the years ended December 31, 2014, 2013, and 2012 was $13.4 million, $20.7million, and $22.1 million, respectively.During the year ended December 31, 2014, the Company settled PSUs that were granted in 2011, which earned a 0.55-timesmultiplier, by issuing a net 85,121 shares of the Company’s common stock in accordance with the terms of the PSU awards. TheCompany and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll taxwithholdings as provided for in the plan document and award agreements. As a result, 45,042 shares were withheld to satisfy incomeand payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2014.During the year ended December 31, 2013, the Company settled PSUs that were granted in 2010, which earned a 1.725-timesmultiplier, by issuing a net 387,461 shares of the Company’s common stock in accordance with the terms of the PSU awards. TheCompany and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll taxwithholdings as provided for in the plan document and award agreements. As a result, 200,050 shares were withheld to satisfy incomeand payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2013.During the year ended December 31, 2012, the Company settled PSUs that were granted in 2009, which earned a 2.0-timesmultiplier, by issuing a net 812,562 shares of the Company’s common stock in accordance with the terms of the PSU awards. TheCompany and the majority of grant participants mutually agreed to net share settle the awards to cover income and payroll taxwithholdings as provided for in the plan document and award agreements. As a result, 406,866 shares were withheld to satisfy incomeand payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs for 2012.116Restricted Stock Units Under the Equity Incentive Compensation PlanThe Company grants RSUs to eligible employees as a part of its equity incentive compensation program. Restrictions andvesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the awardagreements. Each RSU represents a right for one share of the Company’s common stock to be delivered upon settlement of the award atthe end of a specified period. RSUs are recognized as general and administrative and exploration expense over the vesting periods ofthe award.The total expense associated with RSUs for the years ended December 31, 2014, 2013, and 2012, was $13.9 million, $13.1million, and $9.8 million, respectively. As of December 31, 2014, there was $22.5 million of total unrecognized expense related tounvested RSU awards, which is being amortized through 2017. 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 before grant.A summary of the status and activity of non-vested RSUs is presented below: For the Years Ended December 31, 2014 2013 2012 RSUs Weighted-AverageGrant-DateFair Value RSUs Weighted-AverageGrant-DateFair Value RSUs Weighted-AverageGrant-DateFair ValueNon-vested at beginning ofyear580,431 $57.05 496,244 $51.81 308,877 $44.33Granted234,560 $83.98 329,939 $60.01 379,332 $49.47Vested(253,031) $58.19 (207,376) $49.73 (166,672) $32.72Forfeited(46,236) $62.06 (38,376) $54.37 (25,293) $51.06Non-vested at end of year515,724 $68.29 580,431 $57.05 496,244 $51.81The fair value of RSUs granted in 2014, 2013, and 2012 was $19.7 million, $19.8 million, and $18.8 million, respectively. TheRSUs granted in 2014, 2013, and 2012 vest 1/3 on each of the first three anniversary dates of the awards.The total fair value of RSUs that vested during the years ended December 31, 2014, 2013, and 2012, was $14.7 million, $10.3million, and $5.4 million, respectively.During the years ended December 31, 2014, 2013, and 2012, the Company settled 253,031, 207,378, and 166,670 RSUs,respectively. The Company and the majority of grant participants mutually agreed to net share settle the awards to cover income andpayroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued net shares ofcommon stock of 171,597, 139,391, and 116,813 for 2014, 2013, and 2012, respectively. The remaining 81,434, 67,987, and 49,857shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon the delivery of the shares underlyingthose RSUs for 2014, 2013, and 2012, respectively.117Stock Option Grants Under the Equity Incentive Compensation 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, 2014, there was no unrecognized compensation expense related to stock option awards.A summary of activity associated with the Company’s Stock Option Plans during the last three years is presented in thefollowing table: Weighted - Average Aggregate Exercise Intrinsic Shares Price ValueFor the year ended December 31, 2012 Outstanding, start of year508,214 $13.86 Exercised(240,368) $12.65 $11,842,575Forfeited— $— Outstanding, end of year267,846 $14.95 $9,983,177Vested and exercisable at end of year267,846 $14.95 $9,983,177For 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.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, 2014, 2013, and 2012. Cash received from exercises under all share-based payment arrangements for the years endedDecember 31, 2014, 2013, and 2012, was $4.0 million, $3.2 million, and $3.0 million, respectively.118Director SharesIn 2014, 2013, and 2012, the Company issued 27,677, 28,169, and 30,486 shares, respectively, of the Company’s commonstock to its non-employee directors pursuant to the Company’s Equity Plan. The Company recorded compensation expense related tothese issuances of $1.6 million, $1.4 million, and $1.3 million for the years ended December 31, 2014, 2013, and 2012, 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 by the director, in which case that director’s shares vestimmediately.Employee 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 fairmarket value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market valueof the stock on the first or last day of the purchase period. All shares issued under the ESPP on or after December 31, 2011, have nominimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company has 1.1 million sharesavailable under the ESPP for issuance as of December 31, 2014. Shares issued under the ESPP totaled 83,136 in 2014, 77,427 in 2013,and 66,485 in 2012. Total proceeds to the Company for the issuance of these shares were $4.1 million, $3.7 million, and $2.8 millionfor the years ended December 31, 2014, 2013, and 2012, respectively.The fair value of ESPP shares was measured at the date of grant using the Black-Scholes-Merton option-pricing model.Expected volatility was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is basedon 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, 2014 2013 2012Risk free interest rate0.1% 0.1% 0.1%Dividend yield0.1% 0.2% 0.2%Volatility factor of the expected marketprice of the Company’s common stock33.0% 41.1% 47.8%Expected life (in years)0.5 0.5 0.5The Company expensed $1.1 million, $1.1 million, and $948,000 for the years ended December 31, 2014, 2013, and 2012,respectively, based on the estimated fair value of grants.119401(k) PlanThe Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement IncomeSecurity Act 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 may make additional contributions at its discretion. Beginning in 2014, the Company also matches employeecontributions up to six percent of the employee’s bonus paid pursuant to the Company’s cash bonus plan. The Company’s matchingcontributions to the 401(k) Plan were $6.4 million, $4.2 million, and $3.5 million for the years ended December 31, 2014, 2013, and2012, respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years.Non-qualified Deferred Compensation PlanIn January 2014, the Company established a non-qualified deferred compensation (“NQDC”) plan intended to provide planparticipants with the ability to plan for income tax events and the opportunity to receive a benefit for matching contributions in excessof IRC limits applicable to the Company’s 401(k) plan. The NQDC plan is designed to allow employee participants to defer a portion ofbase salary and cash bonuses paid pursuant to the Company’s cash bonus plan and director participants to defer a portion of the cashretainer paid to directors. Each year, participating employees may elect to defer (i) between 0% and 50% of their base salary and(ii) between 0% and 100% of the cash bonus paid pursuant to the cash bonus plan, and participating directors may elect to deferbetween 0% and 100% of their cash retainer. The NQDC plan requires the Company to make contributions for each eligible employeeequal to 100% of the deferred amount for such employee, limited to 6% of such employee’s base salary and cash bonus. Each eligibleemployee’s interest in contributions made by the Company will vest 40% after the second year of such employee’s service to theCompany, and 20% per year thereafter. A participant’s account will be distributed based upon the participant’s payment election madeat the time of deferral. A participant may elect to have distributions made in lump sum or in annual installments ranging for a periodfrom 1 to 10 years. Participants in the NQDC plan are currently limited to the Company’s officers and directors.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. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after theCompany has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result,the 2007 pool was the last Net Profits Plan pool established by the Company.120Cash 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, 2014 2013 2012 (in thousands)General and administrative expense$8,326 $13,734 $15,565Exploration expense690 1,310 1,751Total$9,016 $15,044 $17,316Additionally, the Company made or accrued cash payments under the Net Profits Plan of $8.3 million, $10.3 million, and $2.3million for the years ended December 31, 2014, 2013, and 2012, respectively, as a result of divestiture proceeds. The cash paymentsare accounted for as a reduction in the gain (loss) on divestiture activity line item in the accompanying statements 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. The amount that would be allocatedto exploration expense is minimal in comparison. Over time, less of the amount distributed relates to prospective exploration efforts asmore of the amount distributed is paid to employees that have terminated employment and do not provide ongoing exploration supportto 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”).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 December31.121 For the Years Ended December 31, 2014 2013 (in thousands)Change in benefit obligation: Projected benefit obligation at beginning of year$43,285 $40,237Service cost6,335 6,291Interest cost2,191 1,627Plan amendments— —Actuarial (gain) loss8,821 (1,577)Benefits paid(2,765) (3,293)Projected benefit obligation at end of year57,867 43,285 Change in plan assets: Fair value of plan assets at beginning of year24,658 20,254Actual return on plan assets737 2,726Employer contribution5,310 4,971Benefits paid(2,765) (3,293)Fair value of plan assets at end of year27,940 24,658Funded status at end of year$(29,927) $(18,627)The Company’s underfunded status for the Pension Plans for the years ended December 31, 2014 and 2013, is $29.9 millionand $18.6 million, respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. Noplan assets of the Qualified Pension Plan were returned to the Company during the fiscal year ended December 31, 2014. There are noplan assets in the Nonqualified Pension Plan.Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2014 2013 (in thousands)Projected benefit obligation$57,867 $43,285 Accumulated benefit obligation$43,205 $32,396Less: Fair value of plan assets(27,940) (24,658)Underfunded accumulated benefit obligation$15,265 $7,738Pension 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.122Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensiveloss as of December 31, 2014 and 2013, consist of: As of December 31, 2014 2013 (in thousands)Unrecognized actuarial losses$17,812 $8,439Unrecognized prior service costs118 136Unrecognized transition obligation— —Accumulated other comprehensive loss$17,930 $8,575The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over thenext fiscal year is $1.2 million.Pre-tax changes recognized in other comprehensive income (loss) during 2014, 2013, and 2012, were as follows: For the Years Ended December 31, 2014 2013 2012 (in thousands)Net actuarial gain (loss)$(10,062) $2,766 $(4,680)Prior service cost— — —Less: Amortization of: Prior service cost(17) (17) (17)Actuarial loss(689) (1,222) (754)Total other comprehensive income (loss)$(9,356) $4,005 $(3,909)Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2014 2013 2012 (in thousands)Components of net periodic benefit cost: Service cost$6,335 $6,291 $4,934Interest cost2,191 1,627 1,374Expected return on plan assets that reducesperiodic pension cost(1,978) (1,538) (1,165)Amortization of prior service cost17 17 17Amortization of net actuarial loss689 1,222 754Net periodic benefit cost$7,254 $7,619 $5,914Gains 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.123Pension Plan AssumptionsWeighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are asfollows: As of December 31, 2014 2013 2012Projected benefit obligation Discount rate4.3% 5.0% 3.9%Rate of compensation increase6.2% 6.2% 6.2%Net periodic benefit cost Discount rate5.0% 3.9% 4.7%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 2015 2014 2013Equity securities 42.0% 39.6% 43.6%Fixed income securities 35.0% 33.9% 32.2%Other securities 23.0% 26.5% 24.2%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 2014 and 2013. 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.124Fair Value AssumptionsThe fair values of the Company’s Qualified Pension Plan assets as of December 31, 2014 and 2013, utilizing the fair valuehierarchy discussed in Note 11 – Fair Value Measurements is as follows: Fair Value Measurements Using:Actual AssetAllocation Total Level 1Inputs Level 2Inputs Level 3Inputs (in thousands)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 — — 1,327Hedge Fund (8)14.8% 4,130 593 — 3,537Collective Investment Trusts (9)4.1% 1,149 — 1,149 —Total Other Securities26.5% 7,416 1,403 1,149 4,864Total Investments100.0% $27,940 $19,908 $3,168 $4,864 December 31, 2013 Cash and Money Market Funds—% $— $— $— $—Equity Securities Domestic (1)29.9% 7,371 4,888 2,483 —International (2)13.7% 3,373 3,373 — —Total Equity Securities43.6% 10,744 8,261 2,483 —Fixed Income Securities High-Yield Bonds (3)5.9% 1,448 1,448 — —Core Fixed Income (4)20.3% 5,006 5,006 — —Floating Rate Corp Loans (5)6.0% 1,483 1,483 — —Total Fixed Income Securities32.2% 7,937 7,937 — —Other Securities: Commodities (6)3.8% 945 945 — —Real Estate (7)3.5% 859 — — 859Hedge Fund (8)14.3% 3,517 955 — 2,562Collective Investment Trusts (9)2.6% 656 — 656 —Total Other Securities24.2% 5,977 1,900 656 3,421Total Investments100.0% $24,658 $18,098 $3,139 $3,421____________________________________________125(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)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. (9)Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value,as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlyinginvestments held by the fund less its liabilities.Included below is a summary of the changes in Level 3 plan assets (in thousands):Balance at January 1, 2013$2,384Purchases742Realized gain on assets161Unrealized gain on assets134Balance at December 31, 2013$3,421Purchases1,232Realized gain on assets144Unrealized gain on assets67Balance at December 31, 2014$4,864ContributionsThe Company contributed $5.3 million, $5.0 million, and $5.4 million, to the Pension Plans in the years ended December 31,2014, 2013, and 2012, respectively. The Company is expected to make a $5.8 million contribution to the Pension Plans in 2015.126Benefit PaymentsThe Pension Plans made actual benefit payments of $2.8 million, $3.3 million, and $1.0 million in the years endedDecember 31, 2014, 2013, and 2012, respectively. Expected benefit payments over the next 10 years are as follows:Years Ending December 31, (in thousands)2015 $3,0062016 $3,0462017 $3,9212018 $4,5582019 $5,2042020 through 2024 $38,427Note 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 completed or acquired. The increase in carrying value is included in provedoil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas propertycosts and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic livesof the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of theCompany’s accompanying 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 and changes tothe Company’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, 2014 2013 (in thousands)Beginning asset retirement obligation$121,186 $120,518Liabilities incurred13,506 18,682Liabilities settled(11,372) (33,129)Accretion expense6,090 5,997Revision to estimated cash flows(7,286) 9,118Ending asset retirement obligation$122,124 $121,186As of December 31, 2014 and 2013, accounts payable and accrued expenses contain $1.3 million and $2.5 million,respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costsassociated with a platform structure that is being retired, which is also included in the table above.127Note 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 the 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 in place include swap and collar arrangements for oil, gas, and NGLs.As of December 31, 2014, the Company had commodity derivative contracts outstanding through the fourth quarter of 2019 fora total of 14.7 million Bbls of oil production, 230.8 million MMBtu of gas production, and 781,000 Bbls of NGL production.In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price,the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than theswap fixed price, the Company pays the difference. For collar agreements, the Company receives the difference between an agreedupon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed uponceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price isbetween the floor and ceiling prices.The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place asof December 31, 2014:Oil ContractsOil SwapsContract Period NYMEX WTI Volumes Weighted-AverageContractPrice (Bbls) (per Bbl)First quarter 2015 1,711,000 $91.96Second quarter 2015 1,639,000 $91.26Third quarter 2015 1,254,000 $90.78Fourth quarter 2015 1,137,000 $90.152016 5,570,000 $88.01All oil swaps 11,311,000 Oil CollarsContract Period NYMEX WTIVolumes Weighted-AverageFloorPrice Weighted-AverageCeilingPrice (Bbls) (per Bbl) (per Bbl)First quarter 2015 882,000 $85.00 $99.53Second quarter 2015 709,000 $85.00 $94.06Third quarter 2015 906,000 $85.00 $91.25Fourth quarter 2015 869,000 $85.00 $92.19All oil collars 3,366,000 128Natural Gas ContractsGas SwapsContract Period Volumes Weighted-AverageContractPrice (MMBtu) (per MMBtu)First quarter 2015 23,548,000 $4.22Second quarter 2015 15,985,000 $3.90Third quarter 2015 14,950,000 $4.03Fourth quarter 2015 13,570,000 $4.022016 48,896,000 $4.122017 37,414,000 $4.162018 35,241,000 $4.212019 28,159,000 $4.28All gas swaps* 217,763,000 ____________________________________________*Natural gas swaps are comprised of IF El Paso Permian (3%), IF HSC (82%), IF NGPL TXOK (1%), IF NNG Ventura (3%), and IFEnable East (11%).Gas CollarsContract Period Volumes Weighted-AverageFloorPrice Weighted-AverageCeilingPrice (MMBtu) (per MMBtu) (per MMBtu)First quarter 2015 2,524,000 $4.00 $4.30Second quarter 2015 2,297,000 $4.00 $4.30Third quarter 2015 2,005,000 $4.00 $4.30Fourth quarter 2015 6,176,000 $3.97 $4.30All gas collars* 13,002,000 ____________________________________________*Natural gas collars are comprised of IF El Paso Permian (4%), IF HSC (80%), IF NNG Ventura (8%), and IF Enable East (8%).NGL ContractsNGL SwapsContract Period Volumes Weighted-AverageContractPrice (Bbls) (per Bbl)First quarter 2015 781,000 $55.42All NGL swaps* 781,000 ____________________________________________*NGL swaps are comprised of OPIS Natural Gasoline Mt Belv Non TET (28%) and OPIS Propane Mt Belv TET (72%).129Derivative 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 $592.1 million and $21.5 millionat December 31, 2014 and 2013, respectively.The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: 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 $70 As of December 31, 2013 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands)Commodity ContractsCurrent assets $21,559 Current liabilities $26,380Commodity ContractsNoncurrent assets 30,951 Noncurrent liabilities 4,640Derivatives not designated as hedginginstruments $52,510 $31,020Offsetting of Derivative Assets and LiabilitiesAs of December 31, 2014 and 2013, all derivative instruments held by the Company were subject to enforceable master nettingarrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting ofamounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that occur on the samedate and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterpartieshave the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’saccounting policy is to 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 2014 2013 2014 2013 (in thousands)Gross amounts presented in the accompanying balance sheets $592,208 $52,510 $(70) $(31,020)Amounts not offset in the accompanying balance sheets (70) (30,652) 70 30,652Net amounts $592,138 $21,858 $— $(368)130Discontinuance of Cash Flow Hedge AccountingAs of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previouslydesignated as cash flow hedges at December 31, 2010. Fair values at December 31, 2010, were frozen in AOCL as of the de-designation date and were reclassified into earnings as the original derivative transactions settled. As of September 30, 2013, allcommodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified intoearnings from AOCL.Subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fairvalues immediately in earnings rather than deferring any such amounts in AOCL. The Company had no derivatives designated as cashflow hedges for the years ended December 31, 2014, 2013, and 2012, and no new gains or losses were deferred to AOCL during theserespective years. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivativeinstruments, including its valuation techniques.The following table summarizes the components of derivative gain presented in the accompanying statements of operations: For the Years Ended December 31, 2014 2013 2012 (in thousands)Derivative settlement (gain) loss: Oil contracts$(28,410) $15,161 $11,893Gas contracts26,706 (30,338) (47,270)NGL contracts(10,911) (6,885) (8,887)Total derivative settlement gain (1)$(12,615) $(22,062) $(44,264) Total derivative (gain) loss: Oil contracts$(457,082) $14,665 $(20,088)Gas contracts(93,267) (14,053) (15,493)NGL contracts(32,915) (3,692) (20,049)Total derivative gain (2)$(583,264) $(3,080) $(55,630)____________________________________________(1) Total derivative settlement gain is reported in the derivative cash settlements line item on the accompanying statements of cash flows within net cashprovided by operating activities with the change in accrued settlements between years being reported in change in accounts receivable and change inaccounts payable and accrued expenses line items. Total derivative settlement gains are adjusted by a $41.0 million decrease attributable to the changein current assets and liabilities at December 31, 2014.(2) Total derivative gain is reported in the derivative gain line item on the accompanying statements of cash flows within net cash provided by operatingactivities. 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 2014 2013 2012 (in thousands)Amount reclassified from AOCLCommodityContracts Other operatingrevenues $— $1,115 $(2,264) 131The realized net hedge loss for the year ended December 31, 2013, and net hedge gain for the year ended December 31, 2012,shown net of income tax in the table above, are comprised of realized settlements on commodity derivative contracts that werepreviously designated as cash flow hedges. Realized hedge gains or losses from the settlement of commodity derivatives previouslydesignated as cash flow hedges are reported in the other operating revenues line item on the accompanying statements of operations. The Company realized a pre-tax net loss of $1.8 million and a pre-tax net gain of $3.9 million from its commodity derivative contractsthat were previously designated as cash flow hedges for the years ended December 31, 2013, and 2012, respectively.Credit Related Contingent FeaturesAs of December 31, 2014, 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 liens on at least 75 percent of the Company’s proved oil and gas properties.Convertible Note Derivative InstrumentThe contingent interest provision of the 3.50% Senior Convertible Notes was an embedded derivative instrument. The 3.50%Senior Convertible Notes were settled during the second quarter of 2012. Please refer to Note 5 - Long-term Debt for additionaldiscussion.Note 11 – Fair Value MeasurementsThe Company follows fair value measurement authoritative accounting guidance for all assets and liabilities measured at fairvalue. Authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer aliability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs arethe preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fairvalue hierarchy for grouping these 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 and where they wereclassified 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 $—Net Profits Plan (1)$— $— $27,136____________________________________________(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.(2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.132The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they wereclassified within the hierarchy as of December 31, 2013: Level 1 Level 2 Level 3 (in thousands)Assets: Derivatives (1)$— $52,510 $—Proved oil and gas properties (2)$— $— $62,178Unproved oil and gas properties (2)$— $— $3,280Oil and gas properties held for sale (2)$— $— $650Liabilities: Derivatives (1)$— $31,020 $—Net Profits Plan (1)$— $— $56,985____________________________________________(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.Both 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 and takes 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.133The 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 accounting authoritative 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.Net 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. The calculation of this liability is asignificant management estimate. A discount rate of 12 percent is used to calculate this liability, which is 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, 2014, woulddiffer by approximately $2.6 million. A one percent increase or decrease in the discount rate would result in a change of approximately$1.1 million. Actual cash payments to be made to participants in future periods are dependent on realized actual production, realizedcommodity prices, and actual costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actualcash payments 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. 134The 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, 2014 2013 2012 (in thousands)Beginning balance$56,985 $78,827 $107,731Net increase (decrease) in liability (1)(12,492) 3,527 (9,251)Net settlements (1) (2)(17,357) (25,369) (19,653)Transfers in (out) of Level 3— — —Ending balance$27,136 $56,985 $78,827____________________________________________(1)Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanyingstatements of operations.(2)Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash paymentsmade or accrued under the Net Profits Plan of $8.3 million, $10.3 million, and $2.3 million relating to divestiture proceeds for theyears ended December 31, 2014, 2013, and 2012, respectively.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, 2014 or2013, as they are recorded at historical value. As of December 31, 2014 2013 (in thousands)2019 Notes$350,018 $374,2902021 Notes$343,000 $373,6252022 Notes (1)$556,500 $—2023 Notes$379,000 $422,0002024 Notes$435,000 $475,315____________________________________________(1) The 2022 Notes were issued on November 17, 2014.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 that 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 selected by the Company’s management. The calculation of the discount rate is based on the best information availableand was estimated to be 12 percent as of December 31, 2014, and 2013. The Company believes that the discount rate is representativeof current market conditions and takes into account estimates of future cash payments, expectations of possible variations in the amountand/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecasted based on NYMEXstrip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream.The prices for NGLs are forecasted using OPIS135pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted asdeemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on anestimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is notavailable, the Company utilizes the income valuation technique discussed above.As a result of asset write-downs, proved oil and gas properties measured at fair value within the accompanying balance sheetstotaled $33.4 million and $62.2 million as of December 31, 2014, and 2013, respectively.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. Unproved properties classified as held for sale are valued using a market approach, based on an estimatedselling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, theCompany estimates acreage value based on the price received for similar acreage in recent transactions by the Company or othermarket participants in the principal market.Impaired unproved oil and gas properties measured at fair value were written down to zero and $3.3 million in theaccompanying balance sheets as of December 31, 2014, and 2013, respectively.The 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 - Acquisitions, Divestitures, and Assets Held for Sale for additionalinformation on the fair value of assets acquired during 2014.Asset Retirement ObligationsThe Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at thepoint of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value ofmoney, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of theinputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.Note 12 - Acquisition and Development AgreementIn June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui. Pursuant to the Acquisitionand Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil andgas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration forthe oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to theCompany’s remaining interest in these assets until Mitsui expended an aggregate $680.0 million on behalf of the Company. TheAcquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues,paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date,which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling andcompletion costs for the affected acreage.136During 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.Note 13 - Suspended Well CostsThe following table reflects the net changes in capitalized exploratory well costs during 2014, 2013, and 2012. 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, 2014 2013 2012 (in thousands)Beginning balance on January 1,$34,527 $9,100 $18,600Additions to capitalized exploratory well costs pending thedetermination of proved reserves43,589 34,527 9,100Reclassifications to wells, facilities, and equipment based on thedetermination of proved reserves(33,340) (9,100) (5,865)Capitalized exploratory well costs charged to expense(1,187) — (12,735)Ending balance at December 31,$43,589 $34,527 $9,100As of December 31, 2014, there were no exploratory well costs that were capitalized for more than one year.137Supplemental 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, 2014 2013 2012 (in thousands)Development costs (1)$1,782,324 $1,350,116 $1,346,216Exploration costs288,270 168,612 220,921Acquisitions Proved properties272,902 29,859 5,773Unproved properties (2)368,208 172,546 114,971Total, including asset retirement obligation (3)(4)$2,711,704 $1,721,133 $1,687,881____________________________________________(1)Includes facility costs of $75.1 million, $49.5 million, and $62.2 million for the years ended December 31, 2014, 2013, and 2012, respectively.(2)Includes $288.7 million, $58.5 million, and $3.4 million of unproved properties acquired as part of proved property acquisitions for the years endedDecember 31, 2014, 2013, and 2012, respectively. The remaining balance relates to leasing activity.(3)Includes capitalized interest of $16.0 million, $11.0 million, and $12.1 million for the years ended December 31, 2014, 2013, and 2012, respectively.(4)Includes amounts relating to estimated asset retirement obligations of $11.4 million, $26.8 million, and $30.6 million for the years ended December 31,2014, 2013, and 2012, 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 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.138The 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, 2014. 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, 2014 (1) 2013 (2) 2012 (3) Oil Gas NGLs Oil Gas NGLs Oil Gas NGLs (MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl) (MMBbl) (Bcf) (MMBbl)Total proved reserves: Beginning of year126.6 1,189.3 103.9 92.2 833.4 62.3 71.7 664.0 27.5Revisions ofprevious estimate(5.1) 46.0 7.8 (5.2) 68.8 (1.3) (4.5) (123.3) (2.4)Discoveries andextensions15.0 103.5 10.5 34.6 399.2 39.8 17.1 297.4 30.6Infill reserves in anexisting provedfield32.0 270.8 24.1 21.6 118.7 13.2 19.2 125.1 12.7Sales of reserves (4)(1.9) (1.1) — (3.4) (85.1) (0.6) (1.0) (11.0) —Purchases ofminerals in place19.8 10.9 0.2 0.7 3.6 — 0.1 1.2 —Production(16.7) (152.9) (13.0) (13.9) (149.3) (9.5) (10.4) (120.0) (6.1)End of year (5)169.7 1,466.5 133.5 126.6 1,189.3 103.9 92.2 833.4 62.3 Proved developed reserves: Beginning of year70.2 569.2 43.8 58.8 483.2 27.2 50.3 451.2 15.2End of year89.3 784.6 66.7 70.2 569.2 43.8 58.8 483.2 27.2Proved undeveloped reserves: Beginning of year56.3620.160.2 33.5 350.2 35.1 21.4 212.8 12.3End of year80.4682.066.8 56.3 620.1 60.2 33.5 350.2 35.1____________________________________________Note: Amounts may not recalculate due to rounding.(1)For the year ended December 31, 2014, the Company added 143.9 MMBOE from its drilling program, the majority of which related to activity in theEagle Ford shale in south Texas and Bakken/Three Forks plays in North Dakota. These additions are included in discoveries and extensions andinfill reserves. The Company had upward engineering revisions of 10.4 MMBOE primarily related to improved performance and lower operatingexpenses in its operated Eagle Ford assets.(2)For the year ended December 31, 2013, of the 5.0 MMBOE upward revision of a previous estimate, 0.6 MMBOE and 4.4 MMBOE relate to price andperformance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2013, were $96.94 per Bbl,$3.67 per MMBtu, and $40.29 per Bbl for oil, natural gas, and NGLs respectively. These prices were two percent higher, 33 percent higher, and 12percent lower, respectively, than the prices used in 2012. The Company added 195.5 MMBOE from its drilling program, the majority of whichrelated to activity in the Eagle Ford shale in south Texas and Bakken/Three Forks plays in North Dakota. These additions are included indiscoveries and extensions and infill reserves.(3)For the year ended December 31, 2012, of the 27.4 MMBOE downward revision of a previous estimate, 12.1 MMBOE and 15.3 MMBOE relate toprice and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2012, were $94.71per Bbl, $2.76 per MMBtu, and $45.65 per Bbl, for oil, natural gas, and NGLs respectively. These prices were two percent lower, 33 percent lower,and 23 percent lower,139respectively, than the prices used in 2011. The Company added 150.0 MMBOE from its drilling program, the majority of which related to activity inthe Eagle Ford shale in south Texas. These additions are included in discoveries and extensions and infill reserves.(4)The Company divested of certain non-core assets during 2014, 2013, and 2012. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Heldfor Sale for additional information.(5)For the years ended December 31, 2014, 2013, and 2012, amounts included insignificant net gas imbalance positions.Standardized 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, 2014 2013 2012Oil (per Bbl)$84.65 $90.19 $86.80Gas (per Mcf)$4.63 $3.99 $3.08NGLs (per Bbl)$35.48 $35.92 $41.00140The 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, 2014 2013 2012 (in thousands)Future cash inflows$25,897,730 $19,895,360 $13,129,243Future production costs(9,986,239) (7,771,747) (5,013,720)Future development costs(3,294,164) (2,891,325) (1,742,978)Future income taxes(3,511,352) (2,722,230) (1,609,397)Future net cash flows9,105,975 6,510,058 4,763,14810 percent annual discount(3,407,192) (2,500,619) (1,742,134)Standardized measure of discounted future netcash flows$5,698,783 $4,009,439 $3,021,014The principle sources of changes in the standardized measure of discounted future net cash flows are: For the Years Ended December 31, 2014 2013 2012 (in thousands)Standardized measure, beginning of year$4,009,439 $3,021,014 $2,580,040Sales of oil, gas, and NGLs produced, net of productioncosts(1,765,666) (1,602,505) (1,081,997)Net changes in prices and production costs(75,966) 142,199 (550,293)Extensions, discoveries and other including infill reservesin an existing proved field, net of related costs1,819,657 2,309,075 1,872,810Sales of reserves in place(49,736) (259,031) (41,020)Purchase of reserves in place413,175 30,771 3,785Previously estimated development costs incurred duringthe period1,015,694 581,107 163,937Changes in estimated future development costs138,247 68,613 47,980Revisions of previous quantity estimates167,500 82,226 (452,454)Accretion of discount552,852 384,914 346,118Net change in income taxes(399,587) (690,953) 53,005Changes in timing and other(126,826) (57,991) 79,103Standardized measure, end of year$5,698,783 $4,009,439 $3,021,014141Quarterly Financial Information (unaudited)The Company’s quarterly financial information for fiscal years 2014 and 2013 is as follows (in thousands, except per shareamounts): First Second Third (2) Fourth (2) (3) Quarter Quarter Quarter QuarterYear Ended December 31, 2014 Total operating revenues$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 $— Year Ended December 31, 2013 Total operating revenues$484,180 $559,360 $613,107 $636,727Total operating expenses437,982 415,076 475,623 596,438Income from operations$46,198 $144,284 $137,484 $40,289Income before income taxes$27,109 $122,727 $113,024 $15,751Net income$16,727 $76,522 $70,690 $6,996Basic net income per common share (1)$0.25 $1.15 $1.06 $0.10Diluted net income per common share (1)$0.25 $1.13 $1.04 $0.10Dividends declared per common share$0.05 $— $0.05 $—____________________________________________(1)Amounts may not sum due to rounding.(2)The third and fourth quarters of 2014 included net derivative gains of $190.7 million and $616.7 million, respectively. Please refer to the captionDerivative gain included in Comparison of Financial Results and Trends between 2014 and 2013 included in Part II, Item 7 of this report for additionaldiscussion.(3)The fourth quarter of 2014 and 2013 included impairment of proved properties of $84.5 million and $110.9 million, respectively, and abandonment andimpairment of unproved properties of $57.2 million and $37.6 million, respectively. Please refer to the caption Impairment of Proved and UnprovedProperties included in Note 1 - Summary of Significant Accounting Policies for additional discussion.ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURENone.ITEM 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.142Our 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 2014 that have materially affected, or are reasonably likely tomaterially affect, our internal control over financial reporting.The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) released the updated Internal Control–Integrated Framework (“2013 Framework”) in May 2013 which superseded the original 1992 Framework. During 2014, we transitionedto the criteria set forth by COSO in the 2013 Framework from the original 1992 Framework. This transition did not materially affect,and is not reasonably likely to materially affect, our internal control over financial reporting.Effective January 1, 2015, we implemented a new enterprise resource planning system (“ERP”) that is expected to materiallyaffect our internal control over financial reporting. In connection with this ERP implementation, we are updating our internal controlover financial reporting, as necessary, to accommodate modifications to our business processes and accounting procedures. We do notbelieve that this ERP implementation will have an adverse effect on our internal control over financial reporting.143Management’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, 2014. 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, 2014.The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internalcontrols over financial reporting. That report immediately follows this report.144Report 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, 2014, 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, 2014, 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, 2014, and the related consolidated statementsof operations, comprehensive income (loss), stockholders’ equity, and cash flows for the year then ended and our report datedFebruary 25, 2015 expressed an unqualified opinion thereon./s/ Ernst & Young LLPDenver, ColoradoFebruary 25, 2015145ITEM 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 2015 annual meeting ofstockholders to be filed within 120 days from December 31, 2014.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 2015 annual meeting of stockholders to be filed within 120 days from December 31,2014.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 2015 annual meeting of stockholdersto be filed within 120 days from December 31, 2014.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 2015 annual meeting of stockholders to be filed within 120 days fromDecember 31, 2014.146Securities 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, 2014: (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) 515,724 N/A Performance share units (1)(3)(4) 745,264 N/A Total for Equity Incentive Compensation Plan 1,260,988 $— 3,602,270Employee Stock Purchase Plan (2) — — 1,146,921Equity compensation plans not approved by securityholders — — —Total for all plans 1,260,988 $— 4,749,191____________________________________________(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. The Equity Plan serves as the successor to the St. Mary Land &Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company RestrictedStock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). Allgrants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under aPredecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of theinstruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009, 2010, and 2013 and eachamended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2014, 2013, and 2012 under theEquity Plan were 464,641, 632,939, and 724,671, 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 83,136, 77,427, and 66,485 in 2014, 2013, and 2012,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 $68.29 and $67.48, 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.147ITEM 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 2015 annualmeeting of stockholders to be filed within 120 days from December 31, 2014.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 2015 annual meeting of stockholders to be filed within 120 days from December 31, 2014.148PART IVITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules:Reports of Independent Registered Public Accounting Firms87Consolidated 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 2.1Purchase and Sale Agreement dated June 9, 2011, among SM Energy Company, Statoil Texas Onshore PropertiesLLC, and Talisman Energy USA Inc. (filed as Exhibit 2.1 to the registrant’s Quarterly Report on Form 10-Q for thequarter ended June 30, 2011 and incorporated herein by reference)2.2Acquisition 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)2.3First 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)2.4***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)2.5***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 By-Laws of SM Energy Company amended effective as of December 16, 2014 (filed asExhibit 3.1 to the registrant’s Current Report on Form 8-K filed on December 19, 2014, and incorporated herein byreference)1494.1Indenture related to the 3.50% Senior Convertible Notes due 2027, dated as of April 4, 2007, between St. MaryLand & Exploration Company and Wells Fargo Bank, National Association, as trustee (including the form of 3.50%Senior Convertible Notes due 2027) (filed as Exhibit 4.1 to the registrant’s Current Report on Form 8-K filed onApril 4, 2007 and incorporated herein by reference)4.2Indenture 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)4.3Indenture 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)4.4Indenture 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)4.5Indenture 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)4.6Indenture 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)4.7Registration Rights Agreement, dated November 17, 2014, by and among SM Energy Company and Merrill Lynch,Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, asrepresentatives of several purchasers (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed onNovember 18, 2014, 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)10.3†Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to the registrant’s QuarterlyReport on Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference)10.4†Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.9 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein byreference)10.5†Employment Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the registrant’s Current Report onForm 8-K filed on May 4, 2006 and incorporated herein by reference)10.6Supplement 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)10.7Deed 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)10.8†Equity Incentive Compensation Plan as Amended and Restated as of March 26, 2009 (filed as Exhibit 10.1 to theregistrant’s Current Report on Form 8-K filed on May 27, 2009, and incorporated herein by reference)15010.9†Equity Incentive Compensation Plan As Amended and Restated as of April 1, 2010 (filed as Exhibit 10.1 to theregistrant’s Current Report on Form 8-K filed on June 2, 2010, and incorporated herein by reference)10.10sSM Energy Company Equity Incentive Compensation Plan, As Amended as of July 30, 2010 (filed as Exhibit 10.7to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporatedherein by reference)10.11†Third Amendment to Employee Stock Purchase Plan dated September 23, 2009 (filed as Exhibit 10.3 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and incorporated herein byreference)10.12†Fourth Amendment to Employee Stock Purchase Plan dated December 29, 2009 (filed as Exhibit 10.46 to theregistrant’s Annual Report on Form 10-K for the year ended December 31, 2009, and incorporated herein byreference)10.13sEmployee Stock Purchase Plan, As Amended and Restated as of July 30, 2010 (filed as Exhibit 10.4 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein byreference)10.14†Form of Performance Share and Restricted Stock Unit Award Agreement as of July 1, 2010 (filed as Exhibit 10.3 tothe registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein byreference)10.15†Form of Performance Share and Restricted Stock Unit Award Notice as of July 1, 2010 (filed as Exhibit 10.4 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein byreference)10.16†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)10.17***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)10.18sNet 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)10.19sSM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan, As Amended as of July 30, 2010(filed as Exhibit 10.8 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010and incorporated herein by reference)10.20†Form of Amendment to Form of Change of Control Executive Severance Agreement (filed as Exhibit 10.1 to theregistrant’s Current Report on Form 8-K filed on December 29, 2010, and incorporated herein by reference) 10.21†Amendment to A.J. Best Employment Agreement dated December 31, 2010 (filed as Exhibit 10.28 to theregistrant’s Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein byreference)10.22†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)10.23+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)10.24Fourth Amended and Restated Credit Agreement dated May 27, 2011 among SM Energy Company, Wells FargoBank, National Association, as Administrative Agent, and the Lenders party thereto (filed as Exhibit 10.1 to theregistrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein byreference)10.25Gas 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)15110.26Gathering 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)10.27Gas 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)10.28†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)10.29†Form of Performance Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.6 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)10.30†Form of Restricted Stock Unit Award Agreement as of July 1, 2011 (filed as Exhibit 10.7 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended June 30, 2011, and incorporated herein by reference)10.31†Form of Performance Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.1 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)10.32†Form of Restricted Stock Unit Award Agreement as of September 6, 2011 (filed as Exhibit 10.2 to the registrant’sQuarterly Report on Form 10-Q for the quarter ended September 30, 2011, and incorporated herein by reference)10.33†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)10.34†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)10.35†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)10.36Fifth 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 of Form 8-K filed on April 15, 2013, and incorporated herein by reference)10.37†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)10.38†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)10.39†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)10.40†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)10.41*†Summary of Compensation Arrangements for Non-Employee Directors10.42†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)10.43Second 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 of Form 8-K filed on December 16, 2014, andincorporated herein by reference)15212.1*Computation of Ratio of Earnings to Fixed Charges21.1*Subsidiaries of Registrant23.1*Consent of Ernst & Young LLP23.2*Consent of Deloitte & Touche LLP23.3*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.153SIGNATURESPursuant 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 25, 2015By:/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, 2014, 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 25, 2015Javan D. Ottoson (Principal Executive Officer) /s/ A. WADE PURSELL Executive Vice President and Chief FinancialOfficer February 25, 2015A. Wade Pursell (Principal Financial Officer) /s/ MARK T. SOLOMON Vice President - Controller and AssistantSecretary February 25, 2015Mark T. Solomon (Principal Accounting Officer) 154Signature Title Date /s/ WILLIAM D. SULLIVAN Chairman of the Board of Directors February 25, 2015William D. Sullivan /s/ ANTHONY J. BEST Director February 25, 2015Anthony J. Best /s/ LARRY W. BICKLE Director February 25, 2015Larry W. Bickle /s/ STEPHEN R. BRAND Director February 25, 2015Stephen R. Brand /s/ WILLIAM J. GARDINER Director February 25, 2015William J. Gardiner /s/ LOREN M. LEIKER Director February 25, 2015Loren M. Leiker /s/ RAMIRO G. PERU Director February 25, 2015Ramiro G. Peru /s/ JULIO M. QUINTANA Director February 25, 2015Julio M. Quintana /s/ ROSE M. ROBESON Director February 25, 2015Rose M. Robeson /s/ JOHN M. SEIDL Director February 25, 2015John M. Seidl 155EXHIBIT 10.41SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORSThe following is a description of the standard arrangements pursuant to which directors of SM Energy are compensatedfor services 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 2014 - 2015 as it relates to the fiscal period from May 2014 through May 2015, target compensation for eachmember of the Board of Directors has been set at $180,000 annually, plus a retainer paid in lieu of committee and attendance fees. Asdescribed more fully below, the actual value of compensation may be higher or lower depending on the results of the restricted stockcomponent of director compensation. Primary director compensation is in the form of stock grants and is fully described below. Theretainer component of director compensation for non-employee directors consists of an annual retainer of $90,000 for committee andboard meeting fees paid in SM Energy common stock or cash as selected by the director; provided that in the event any director attendsin excess of 30 Board and committee meetings in the aggregate during the period from May 2014 through May 2015, such directorshall receive $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 2,307 shares of SM Energy common stock issued on May 21,2014, under SM Energy's Equity Incentive Compensation Plan. As compensation for her service for the 2014 - 2015service period following her appointment to the Board, Rose M. Robeson received 1,967 shares of SM Energycommon stock issued on July 11, 2014. As compensation for his service for the 2014 - 2015 service period followinghis appointment to the Board, Ramiro G. Peru received 1,717 shares of SM Energy common stock issued on August20, 2014. These shares are earned over the one-year board service period and carry a subsequent six month transferrestriction 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 1,090 shares ofSM Energy common stock issued on May 21, 2014, 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 SMEnergy.3)Larry W. Bickle, William J. Gardiner, Loren M. Leiker, Julio M. Quintana and William D. Sullivan each elected toreceive SM Energy common stock for their retainer, which resulted in a grant of 1,154 shares of SM Energy commonstock issued on May 21, 2014, under SM Energy's Equity Incentive Compensation Plan. These shares are earned overthe one-year Board service period and carry a subsequent six month transfer restriction imposed by SM Energy.Stephen R. Brand and John M. Seidl each elected to receive a $90,000 cash payment for their retainer.4)Rose M. Robeson elected to receive SM Energy common stock for her pro rata retainer, which resulted in a grant of984 shares of SM Energy common stock issued on July 11, 2014. Ramiro G. Peru elected to receive a cash payment of$67,315 for his pro rata retainer.EXHIBIT 12.1SM Energy CompanyRatio of Earnings to Fixed Charges Year Ended December 31, 20142013201220112010 (in thousands, except ratios) Pretax income from continuing operations$1,064,699$278,611$(83,517)$339,001$314,896 Add: Fixed charges117,147102,75877,84158,03029,558Add: Amortization of capitalized interest11,44811,7849,0955,1072,991Less: Capitalized interest(16,165)(10,952)(12,135)(10,785)(4,337)Earnings before fixed charges$1,177,129$382,201$(8,716)$391,353$343,108 Fixed charges: Interest expense (1)$98,554$89,711$63,720$45,849$24,196Capitalized interest16,16510,95212,13510,7854,337Interest expense component of rent (2)2,4282,0951,9861,3961,025Total fixed charges$117,147$102,758$77,841$58,030$29,558 Ratio of earnings to fixed charges10.03.7—6.711.6Insufficient coverage$—$—$86,557$—$—(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. Four Winds Marketing, LLC, a Colorado limited liability company2. SMT Texas LLC, a Colorado limited liability company3. Energy Leasing, Inc., an Oklahoma corporation4. Belring GP LLC, a Delaware limited liability company5. St. Mary Energy Louisiana LLC, a Delaware limited liability company6. Hilltop Investments, a Colorado general partnership7. Parish Ventures, a Colorado general partnership8. Green Canyon Offshore LLC, a Delaware limited liability company.B. Other subsidiaries of SM Energy Company:1.Box Church Gas Gathering, LLC, a Colorado limited liability company (59%)C.Partnership or limited liability company interests held by SM Energy Company:1.Potato Creek Midstream, LLC, a Pennsylvania limited liability company (70%)2.Trinity River Systems, LTD, a Texas limited partnership (21%)3.1977 H.B Joint Account, a Colorado general partnership (8%)4.1976 H.B Joint Account, a Colorado general partnership (9%)5.1974 H.B Joint Account, a Colorado general partnership (4%)6.Sycamore Gas Systems, an Oklahoma general partnership (3%)D. 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, and Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, and 333-194305 on Form S-8 of our reports dated February 25, 2015, with respect to the consolidated financialstatements of SM Energy Company and subsidiaries, and the effectiveness of internal control over financial reporting of SM EnergyCompany and subsidiaries, included in this Annual Report (Form 10-K) for the year ended December 31, 2014./s/ ERNST & YOUNG LLPDenver, ColoradoFebruary 25, 2015EXHIBIT 23.2CONSENT 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 and Registration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740,333-170351, and 333-194305 on Form S-8 of our report dated February 21, 2013, relating to the 2012 consolidated financialstatements of SM Energy Company and subsidiaries appearing in this Annual Report on Form 10-K of SM Energy Company for theyear ended December 31, 2014./s/ DELOITTE & TOUCHE LLPDenver, ColoradoFebruary 25, 2015EXHIBIT 23.3CONSENT 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, 2014. We hereby further consent to the use of informationcontained in our reports, and the use of our audit letter, as of December 31, 2014, 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, 333-35352, 333-88780, and 333-106438 on Form S-8, andRegistration Statement Nos. 333-58273, 333-134221, 333-151779, 333-165740, 333-170351, and 333-194305 on Form S-8./s/ RYDER SCOTT COMPANY, L.P.Denver, COFebruary 25, 2015EXHIBIT 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 25, 2015/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 25, 2015/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, 2014as 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 25, 2015/s/ A. WADE PURSELLA. Wade PursellExecutive Vice President and Chief Financial OfficerFebruary 25, 2015EXHIBIT 99.1SM ENERGY COMPANYEstimatedFuture ReservesAttributable to CertainLeasehold InterestsSEC ParametersAs ofDecember 31, 2014/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 2, 2015Ms. 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, 2014 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, 2015 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 ofDecember 31, 2014. The properties reviewed by Ryder Scott incorporate 3,094 SM Energy reserve determinations and are locatedin the states of North Dakota, Oklahoma, Texas and Wyoming.The properties reviewed by Ryder Scott account for a portion of SM Energy’s total net proved reserves as of December 31,2014. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by Ryder Scottaddresses 84.1 percent of the total proved developed net liquid hydrocarbon reserves, 85.3 percent of the total proved developednet gas reserves, 86.1 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 95.3 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, 2014 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.SUITE 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 2, 2014Page 2The 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, 2014, 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, 2014 Proved Developed Total Producing Non-Producing Undeveloped ProvedNet Reserves of PropertiesAudited by Ryder Scott Oil/Condensate - MBarrels 63,158 2,236 60,188 125,582Plant Products - MBarrels 60,812 4,950 66,596 132,358Gas – MMCF 629,396 39,600 649,686 1,318,682 Net Reserves of PropertiesNot Audited by Ryder Scott Oil/Condensate - MBarrels 23,060 837 20,231 44,129Plant Products – MBarrels 699 254 231 1,184Gas – MMCF 101,906 13,666 32,290 147,862 Total Net Reserves Oil/Condensate - MBarrels 86,218 3,073 80,420 169,711Plant Products – MBarrels 61,511 5,204 66,827 133,542Gas – MMCF 731,302 53,266 681,976 1,466,544Liquid 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.Reserves 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 3The 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 data available at the time of the estimate, the established or anticipated performance characteristics of the reservoirbeing evaluated and the 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 reserveRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 4quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of thereserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantitiesas proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For provedreserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much morelikely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to berecovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC statesthat “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the totalquantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” Allquantities of reserves within the same reserve category must meet the SEC definitions as noted 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 2014, 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 2014. 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, we consider many factors and assumptions areconsidered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering datawhich cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts offuture production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to beeconomically producible from a given date forward based on existing economic conditions including the prices and costs at whicheconomic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices receivedfor the sale of production and the operating costs and other costs relating to such production may increase or decrease from thoseunder existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from considerationin 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 5The 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, 2014 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 AreaProductPriceReferenceAverageBenchmarkPricesAverageRealizedPricesNorth America United StatesOil/CondensateWTI, Cushing$94.99/Bbl$84.81Bbl NGLsPropane, MT. Belvieu$39.91/Bbl$35.49Bbl GasHenry Hub$4.35/MMBTU$4.57/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in SM Energy’sindividual property evaluations.Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed.The proved gas volumes included herein do not attribute 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 leasesRYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 6and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative andoverhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly tothe leases and wells under terms of operating agreements. The operating costs furnished by SM Energy were accepted as factualdata and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used bySM Energy. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments thatwere 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, 2014. 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 legal, regulatory, politicalor economic obstacles that would significantly alter their plans. While these plans could change from those under existingeconomic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluation.Current 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. Suchfactors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wellsand/or constraints 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 7SM 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, abandonment costs and salvage, product pricesbased on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs,core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we havenot conducted an independent verification of the data furnished by SM Energy. The data described herein were accepted asauthentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to ourattention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual datafurnished to us by SM Energy to be appropriate and sufficient for the purpose of our review of SM Energy’s estimates of reserves.In summary, we consider the assumptions, data, methods and analytical procedures used by SM Energy and as reviewed by usappropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary andappropriate under the circumstances to render the conclusions set forth herein.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 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, 2014 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, it is our opinion that on an aggregate basis the data presented herein for the properties that wereviewed 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 14.9 percent of the total proved net liquid hydrocarbon reserves and 10.1 percent ofthe total proved net gas reserves based on estimates prepared by SM Energy as of December 31, 2014. The other propertiesrepresent 15.8 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, 2014.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 2, 2014Page 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 an attachment 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, 2014 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 2, 2014Page 10RYDER SCOTT COMPANY PETROLEUM CONSULTANTSSM Energy CompanyJanuary 2, 2014Page 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/Experience/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 2014, 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 2, 2014Page 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, Northern Natural Gas and Questar Exploration & Production. For more informationregarding Mr. Baird’s geographic and job specific experience, please refer to the Ryder Scott Company website atwww.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, the Colorado and Utah Board of ProfessionalEngineers recommend continuing education annually, including at least one hour in the area of professional ethics, which Mr. Bairdfulfills. As part of his 2011 continuing education hours, Mr. Baird attended an internally presented sixteen hours of formalizedtraining as well as an eight hour public forum. Mr. Baird attended the 2011 RSC Reserves Conference and various professionalsociety presentations specifically on the new SEC regulations relating to the definitions and disclosure guidelines contained in theUnited States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and GasReporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Baird attended an additional sixteen hours offormalized in-house training during 2012 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources ManagementSystem, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics forconsultants. Mr. Baird was a keynote speaker, presenting the Changing Landscape of the SEC Reporting, at the 2009Unconventional Gas International Conference held in Fort Worth, Texas.Based on his educational background, professional training and more than 40 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 DEFINITIONSPage 1PETROLEUM 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 CONSULTANTSPETROLEUM RESERVES DEFINITIONSPage 2centered 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES DEFINITIONSPage 3PROVED 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.(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 bedetermined. The price shall be the average price during the 12-month period prior to the ending date of the period coveredby the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESPage 2Developed Non-ProducingDeveloped Non-Producing Reserves include shut-in and behind-pipe reserves.Shut-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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