SM Energy - 4th Quarter 2013 Earnings Call
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SM Energy - 4th Quarter 2013 Earnings Call

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SM Energy - 4th Quarter 2013 Earnings Call SM Energy - 4th Quarter 2013 Earnings Call Presentation Transcript

  • 4th Quarter 2013 Earnings Call and Operational Update February 19, 2014
  • Forward Looking Statements - Cautionary Language Except for historical information contained herein, statements in this presentation, including information regarding the business of the Company, contain forward looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward looking statements. These risks include factors such as the availability, proximity and capacity of gathering, processing and transportation facilities; the uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of announced acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected acquisition, divestiture, joint venture, farm down or similar efforts; the volatility and level of oil, natural gas, and natural gas liquids prices; uncertainties inherent in projecting future rates of production from drilling activities and acquisitions; the imprecise nature of estimating oil and gas reserves; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors” section of SM Energy's 2013 Annual Report on Form 10-K. The forward looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, 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. In this presentation, the Company uses the terms “probable,” “possible,” “3P,” and “resources.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations (subject to other conditions). Resources are quantities of oil and gas and related substances estimated to exist in naturally occurring accumulations. SM Energy also uses the term “EUR” (estimated ultimate recovery), which is the sum of reserves remaining as of a given date and cumulative production as of that date. Estimates of probable and possible reserves included in 3P reserves and resources which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. 2
  • Key Messages  SM Energy had record production for the year.  Annual avg. daily production growth of 33%.  4Q12 to 4Q13 production growth of 31%.  2013 was a strong year for proved reserves.  Proved reserves grew 46% year over year.  Drilling F&D costs decreased by 26% year over year.  Balance sheet remains strong with net Debt to TTM EBITDAX of <1x.  SM Energy stock outperformed the EPX index by 33 percentage points in 2013, ending the year up 59%. 3
  • th 4 Quarter 2013 Performance Production 4Q13 Actual Performance 4Q13 Guidance Net Income 143.8 139 - 146 Total production (MMBOE) 13.23 GAAP net income of $7.0 million, or $0.10 per diluted share.  Average daily production (MBOE/d)  Adjusted net income* (non-GAAP) of $85.9 million, or $1.26 per adjusted diluted share. 12.8 - 13.5 Costs LOE ($/BOE) Transportation ($/BOE) Production taxes (% of pre-derivative oil, gas, & NGL revenue) $4.62 $5.67 G&A -- Cash ($/BOE) G&A -- Cash NPP ($/BOE) G&A -- Non-cash ($/BOE) TOTAL G&A ($/BOE) ** $3.07 $0.17 $0.39 $3.63 $2.15 - $2.35 $0.25 - $0.40 $0.45 - $0.60 $2.85 - $3.35 $15.31 $15.00 - $16.00 DD&A ($/BOE) 4.5% $4.65 - $4.90 $5.40 - $5.65 5.0% - 5.5% EBITDAX  EBITDAX* (nonGAAP) of $395.5 million. * Please see adjusted net income and EBITDAX reconciliations in the Appendix. ** 4Q13 G&A per unit expenses were higher than guidance due to performance-based bonus compensation. 4
  • 2013 Proved Reserves and Production 5
  • 2013 Proved Reserve Roll-Forward MMBOE 54% Liquids/ 46% Gas 600 500 53% Liquids/ 47% Gas 195.5 5.0 1.3 18.2 48.3 428.7 400 293.4 219.9 300 200 126.9 Proved Developed 100 Proved Undeveloped 208.9 166.5 0 Beginning Proved Reserves Adds/Infill Acquisitions Revisions Divestitures Production Ending Proved Reserves  Proved reserves increased by 46% from 2012.  Liquid volumes of proved reserves increased 49% year over year. 6
  • Reserve Metrics  Drilling F&D decreased by approximately 26% in 2013 to $7.77 per BOE.  Reserve replacement in excess of 400% for the second consecutive year. F&D $/BOE $25.00 $20.00 $15.00 405% $20.64 $17.10 $12.84 $10.00 $10.44 $5.00 $7.77 $0.00 2009 2010 Drilling F&D costs, excluding revisions 2011 2012 450% 400% 350% 300% 250% 200% 150% 100% 50% 0% Reserve Replacement % Reserve Metrics 2013 Drilling reserve replacement, excluding revisions 7
  • Annual Production 150 132.4 MBOE/d 125 99.7 100 75 50 25 49.8 50.2 17.3 77.5 9.6 16.7 32.5 32.8 2009 2010 38.2 28.3 17.4 22.1 26.0 45.8 54.7 2011 2012 NGL Oil Gas 68.2 0 2013  2013 average daily annual production grew ~33% from 2012.  3-year compounded annual average daily production growth of ~38%.  Liquids volumes have increased 103% since 2011, when the Company began reporting NGL volumes. 8
  • Debt Adjusted Metrics BOE/D.A. Share 5.0 4.0 3.0 Proved reserves per debt adjusted share Production per debt adjusted share 0.3 2.1 0.6 0.4 0.5 2.8 0.5 0.4 0.3 2.0 1.0 0.6 0.7 5.5 3.1 3.8 0.3 0.2 BOE/D.A. Share 6.0 0.1 0.0 0.0 2009 2010 2011 2012 2013  Proved reserves per debt adjusted share grew 47% year over year and 25% compound annual growth over a 3-year period ending December 31, 2013.  Production per debt adjusted share grew by 33% year over year, and 26% compound annual growth over a 3-year period ending December 31, 2013. 9
  • Operational Update: Development Programs 10
  • Quarterly Production 160 143.8 27.5 31.5 35.5 41.6 40.8 71.7 69.7 71.5 2Q13 3Q13 4Q13 131.8 140 120 110.0 115.0 100 20.8 20.5 31.3 34.8 57.9 59.7 4Q12 MBOE/d 138.8 1Q13 80 24.6 60 40 20 NGL Oil Gas 0  4Q13 production mix comprised of 50% liquids.  Quarterly production increased 31% from 4Q12 to 4Q13.  Liquids volumes grew 39% from 4Q12 to 4Q13. 11
  • Operated Eagle Ford Net Production Operational Highlights  The Company made 20 flowing completions during 4Q13 and made 95 flowing completions in 2013.  At year-end 2013, SM Energy had ~240 PDP locations, and ~200 PUD locations with an associated ~240 MMBOE of total proved reserves booked. 80 74.8 66.1 68.1 51.8 18.9 21.1 15.1 5.5 8.2 41.7 38.8 42.8 2Q13 3Q13 4Q13 70 MBOE/d  10% sequential production growth quarter over quarter; 65% quarterly production growth from 4Q12 to 4Q13. 60 50 45.2 40 15.2 3.9 30 20 10 24.2 7.8 6.3 26.1 30.4 4Q12 1Q13 0 NGL Oil Gas  ~145,000 total net acres    ~ 65,000 net acres - Briscoe Ranch ~ 15,000 net acres - Apache Ranch ~ 65,000 net acres - Galvan Ranch 12
  • Operated Eagle Ford Type Curve Regions Area 6 Area 1 Area 4 Area 3A Area 2 Area 5 Area 3B Area 5 13
  • Operated Eagle Ford 2013 Activity Area 6 Area 1 Area 4 Area 3A Area 2 Type Curve Area 2013 Well Count Net Reserve Add (MMBOE) 1 15 2.1 2 4 2.3 3 61 47.7 4 4 1.4 5 1 0.5 6 10 4.7 Total 95 Area 3B 58.6 Area 5 2013 Wells Prior Year Wells 14
  • Op. Eagle Ford CWC Efficiencies 8.0 CWC Capital ($MM) 7.0 14% Reduction 14% Reduction 6.0 5.0 4.0 3.0 2.0 1.0 0.0 2012 Avg Area 1,2,4 Well 2013 Avg Area 1,2,4 Well 2012 Avg Area 3 Well 2013 Avg Area 3 Well 15
  • Inventory Enhancements / Tests  Increasing lateral length  For the 2014 program, extending laterals on most wells out to an average length of 6,500’ from 5,000’.  Extended lateral lengths in Areas 1, 2, and 4 were modeled in the type curve information in the Appendix.  Testing completion design  Increasing sand loading in our frac designs.  Performance enhancement from these larger sand fracs is not incorporated into our type curves in the Appendix. 16
  • 2014 Activity Map Area 6 Area 1 Area 4 Area 3A Area 2 Area 3B 1 12 2 21 60 4 8 5 2014 Planned Activity Well Count 3 Area 5 Type Curve Area 0 6 0 Total 101 17
  • 5 Year Development Plan Area 6 Area 1 Area 4 Area 3A Area 2 2014 2015 2016 2017 2018 Area 3B Area 5 18
  • Non-operated Eagle Ford Operational Highlights Net Production  1% sequential production growth quarter over quarter. MBOE/d 25 20 15 10 15.5 16.0 17.4 4Q12 1Q13 2Q13 19.8 20.0 3Q13 4Q13 5 0  The operator ran approximately 10 drilling rigs during 4Q13.  APC made 84 flowing completions during 4Q13.  During 4Q13, additional compression was commissioned, adding additional throughput capacity. 19
  • Bakken/Three Forks MBOE/d Net Production 18 16 14 12 10 8 6 4 2 0 Operational Highlights  8% sequential growth quarter over quarter; 35% quarterly production growth 4Q12 to 4Q13. 11.9 14.9 16.1 12.2 13.7 4Q12 1Q13 2Q13 3Q13 4Q13  The Company operated 3 rigs during 4Q13 and made 6 gross flowing completions. GOOSENECK ~36,000 acres  RAVEN/BEAR DEN ~43,000acres  Total Bakken/TFS net acreage  ~159,000 Focus area total net acreage  ~79,000 20
  • Raven/Bear Den Bakken / TFS Operated 2013 Activity Type Curve Area Net Reserve Add (MMBOE) Raven/Bear Den Bakken 17/ 10 3.9 Raven/Bear Den TFS North Dakota Well Count Gross/Net 13 / 8 2.6 Total 30 / 18 6.5 Raven/Bear Den = 2013 BAKKEN WELL = 2013 THREE FORKS WELL 21
  • Gooseneck TFS Operated 2013 Activity Type Curve Area North Dakota Gooseneck TFS Well Count Gross/Net Net Reserve Add (MMBOE) 15 / 11 3.5 Gooseneck 22
  • Operated Bakken/Three Forks CWC Efficiencies CWC Capital ($MM) 10.0 9.0 4% Reduction 8.0 4% Reduction 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 2012 Avg Raven/Bear Den Well 2013 Avg Raven/Bear Den Well 2012 Avg Gooseneck Well 2013 Avg Gooseneck Well 23
  • Inventory Enhancements / Tests Raven / Bear Den Completion Tests  Current design: OH packers & sleeves, 26 stages, 3.5MM# proppant, 80K Bbls of fluid (slickwater and XL gel).  Testing:  Increase proppant and fluid volume (4.2MM# & 90K Bbls) on 2 wells.  Results expected 2Q14. Gooseneck Completion Tests  Current design: OH Packers & Sleeves, 26 stages, 2.5MM# proppant, 47K Bbls of fluid (slickwater and XL gel).  Testing:  Increase proppant volume (3MM#) on 3 wells.  Results expected 2Q14.  Modify drilling target interval to improve well performance.  Results expected 3Q14. 24
  • East Raven Current Spacing Strategy  Current inventory (in Appendix) is based on:  Up to 5 Middle Bakken wells per spacing unit.  4 1st Bench Three Forks wells per spacing unit.  This spacing results in ~530’ between wellbores and 1,060’ between wellbores in the same reservoir.  Planning to test down to 880’ between wells in the same reservoir.  Would result in 12 wells per spacing unit.  Would add approximately 110 gross wells to inventory.* Upper Bakken Shale Middle Bakken 1060’ Lower Bakken Shale Three Forks 1st Bench 1060’ Three Forks 2nd Bench *Amounts not included in inventory table in the Appendix. 25
  • Gooseneck Bakken Play Potential  Recent competitor results show economic potential of Bakken in Gooseneck. Participated in 1 non-operated well to date.  High water saturation concerns have been mitigated by competitor activity and log correlation to core data.  SM Energy has 25,378 net acres with Gooseneck Bakken potential.  Gooseneck 2014 Bakken Wells 24 spacing units with potential SM Energy operatorship.  ~74% WI, ~19% royalty burden.  4 confirmation wells in 2014.  Possible inventory addition of 94 gross operated wells and 20+ MMBOE of net resource potential.* *Amounts not included in inventory table in the Appendix. 26
  • Stateline Play Extends Into Montana  Recent competitor results show economic potential of Bakken/Three Forks in MT.  SM Energy has 15,975 net acres in MT Stateline (~89% HBP).  24 spacing units with potential SM Energy operatorship.  ~52% WI, ~15% royalty burden.  2 confirmation wells in 2014.  Possible inventory additions*  158 potential operated wells.  (90 Bakken, 68 Three Forks) - 79 net wells.  94 potential non-operated wells.  (47 Bakken, 47 Three Forks) - 4 net wells.  Aggregate ~30MMBOE of net resource potential. 2014 planned wells *Amounts not included in inventory table in the Appendix. 27
  • Raven/Bear Den 2014 Activity Type Curve Area Well Count Raven/Bear Den Bakken 14 / 10 Raven/Bear Den TFS 18 / 13 Total 32 / 23 2014 planned activity = 2014 BAKKEN WELL = 2014 THREE FORKS WELL 28
  • Gooseneck TFS 2014 Activity Type Curve Area Goosneck TFS Well Count 13 / 8 Gooseneck 2014 planned activity = 2014 THREE FORKS WELL 29
  • Operational Update: New Ventures 30
  • Powder River Basin WY  SM Energy currently has ~140,000 net acres in the Powder River Basin (~100,000 net acres in the Frontier).  Currently running 1 drilling rig developing Frontier. 2nd rig anticipated early 2Q14. Loco (Frontier) 30 Day IP: 1,408 BOE/d  Completing 3rd operated Frontier well in late 1Q14.  2014 budget plan – Drill 10 Frontier drill wells and make 8 completions.  Currently the Company has 16 approved permits in hand.  SM Energy estimates 355 gross/148 net Frontier locations and 264 gross/144 net Shannon/Sussex locations.  Aggregate 215+ MMBOE net total resource potential. Bridger (Shannon) 30 day IP: 499 BOE/d Dandy (Frontier) 30 day IP: 927 BOE/d Op PDP Hz Op 2014 Hz 31
  • Permian Region MBOE/d Net Production 8 7 6 5 4 3 2 1 0 5.5 5.3 4Q12 1Q13 Operational Highlights 6.6 6.8 7.3 2Q13 3Q13 4Q13  7% sequential production growth quarter over quarter; 33% quarterly production growth from 4Q12 to 4Q13.  On its Permian Shales program, SM Energy operated 1-2 drilling rigs during 4Q13 and made 3 flowing completions. 32
  • Midland Basin Focus Map Midland Basin Buffalo ~47,500 Net acres Sweetie Peck ~13,500 Net acres 33
  • Sweetie Peck – Horiz Well Performance Target Interval Lateral Length Stages Peak 30-Day IP (BOE/d) % Oil Proppant Lift Mechanism Dorcus 3035 H Wolfcamp B 4,960 25 1,226 82 White Sand ESP Britain 3133H Wolfcamp B 4,960 25 981 81 RCP Gas Lift CVX 4134 H Wolfcamp B 4,932 25 950 76 LWC ESP Well Name 34
  • Sweetie Peck Potential Wolfcamp ‘B’ Development Wolfcamp B Location Count Producing 3 2014 planned completions 14 Add’l Locations 79 Total Potential Locations 96* Additional Potential  Wolfcamp ‘D’ / Cline: ~50 wells (Test in 4Q14)  Lower Spraberry: ~105 wells * 96 wells assumes 50’ clearance from vertical wells and 880’ spacing. Producing 2014 planned wells Add’l Locations 35
  • Geology Sweetie Peck to Buffalo Buffalo Sweetie Peck 36
  • Buffalo Program Well Name Tatonka 1H Target Interval Lateral Length Stages Peak 30-Day IP (BOE/d) % Oil Proppant Lift Mechanism Wolfcamp B 5,560 28 376 89 LWC ESP 2014 Program  Continue production test on Tatonka 1H. SM-Energy Tatonka #1 Peak 7-Day rate 549 BOE/d Diamondback UL 4-III #1H 24-hr IP rate: 613 BOE/d WC B  Drill and complete a Wolfcamp ‘D’ test in 2Q14. W&T Offshore Chablis #5H 24-hr IP rate: 530 BOE/d WC A 37
  • Midland Basin Wolfcamp B Wells 1,800 1,600 30 Day IP (BOE) 1,400 Dorcus 3035H 1,200 Britain 3133H 1,000 CVX 4134H 800 600 Tatonka #1H 400 200 3000   4000 5000 6000 7000 8000 9000 Lateral Length (ft) 10000 11000 12000 SM Energy wells, in blue, represent a Peak 30 day average. Graph contains allocated month production figures from IHS for non SM wells. 38
  • SM Energy East Texas Prospect Areas Total Net Acreage: ~215,000 Deep Pines Central  Three Geologic Concepts ~91,000 Net acres Deep Pines West ~90,000 Net acres Independence Deep Pines East ~26,000 Net acres ~8,500 Net acres  Eagle Ford Resource Play (East Texas) – Extension of the South Texas Lower Eagle Ford Play northeast of the San Marcos Arch.  Austin Chalk Resource Play – Application of modern unconventional completion techniques in areas where Austin Chalk matrix is hydrocarbon saturated but weakly naturally fractured.  Woodbine Sandstone Play – Hydrocarbon charged, overpressured marine sandstones. 39
  • Woodbine Trap Model Normally Pressured Over-Pressured Hydrocarbon-Saturated Shaley Sandstones (Woodbine Rim Play) Austin Chalk Unconventional Trap Tight, HydrocarbonSaturated Shaley Sandstones (Reservoir & Seal) Conventional Woodbine Hydrocarbon Traps Conventional Trap Woodbine Sandstones Porous, Permeable, Wet Sandstones SM Target Eagle Ford Shale (Hydrocarbon Source) Buda Limestone 40
  • SM Energy East Texas Prospect Areas Target Interval Effective Lateral Length Stages Fluid Volume (Bbl/Stage) 7-Day IP (BOE/d) %Oil BTU Gas FCP (PSI) Horizon 2H Woodbine 2,500 11 7,775 873 41 1,278 1,540 Brollier 1H Eagle Ford 4,450 17 6,500 1,474 6 1,196 6,110 Well Name Horizon 2H Brollier 1H 41
  • 2014 East Texas Program  Drill additional test wells in each of the four prospect areas to delineate and high-grade acreage position.  SM Energy plans to drill eight additional test wells, primarily in the first half of 2014. Well Target Matt Dillon Woodbine Woodbine 2Q14 Doc Woodbine Woodbine Austin Chalk Est. Frac Date 2Q14 Ben Target Cameron Heirs 1Q14 Little Joe Well Est. Frac Date 3Q14 3Q14 Well Blackstone Page * 12H Target Eagle Ford Austin Chalk 2Q14 Walter Johnson Well Target Est. Frac Date Woodbine 2Q14 Est. Frac Date 3Q14 * Non-operated 42
  • Financial Update 43
  • Financial Position TOTAL BOOK CAPITALIZATION (in millions)  At December 31, 2013, the Company’s net debt to trailing EBITDAX was 0.9 and net debt to book capitalization was 45%. $3,500 $3,000 $2,500 $1,607 $2,000 $1,500 $1,000 $500 $0 $500 $400 $350 $0 $350 December 31, 2013  Current revolver commitment is $1.3 billion with borrowing base of $2.2 billion. Revolving Credit Facility Senior Notes due 2019 Senior Notes due 2021 Senior Notes due 2023 Senior Notes due 2024 Stockholders’ Equity 44
  • Financial Position Debt Maturities (in millions) $2,500 $2,000 $1,500 $1,000 $500 $0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Revolving Credit Facility Senior Notes due 2019 Senior Notes due 2023 Senior Notes due 2024 Senior Notes due 2021 45
  • Debt to TTM EBITDAX 5.0x 4.5x 4.0x 3.5x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x Average: 2.4x 1.1 1.2 SM @ 12/31/13 SM @ 9/30/13  SM Energy’s debt to trailing twelve-month EBITDAX is below its peer average of 2.4x. Note: 12/31/13 SM TTM EBITDAX is calculated by Company per Bloomberg definition; 9/30/13 TTM EBITDAX as calculated by Bloomberg as of 9/30/13. Balance sheet data for peers sourced from Bloomberg as of 9/30/2013. Peer Group includes BBG, CLR, COG, CRK, CXO, DNR, EGN, FST, LPI, NFX, QEP, RRC, WLL, XCO, XEC. 46
  • EBITDAX Per Debt Adjusted Share  EBITDAX per debt adjusted share increased by 44% year over year, and compound annual growth of 22% over a 3-year period ending December 31, 2013. EBITDAX Per Debt Adjusted Share $/ D.A. Sahre $20.00 $15.00 $10.00 $5.00 $18.35 $7.81 $10.21 $13.66 $12.72 2011 2012 $0.00 2009 2010 2013 47
  • Key Takeaways  Solid execution on development programs and advancement of new venture plays in 2013.  Strong year over year growth on debt-adjusted per share metrics.  Proved Reserves increased 47%.  Production increased 33%.  EBITDAX increased 44%.  Compelling plan for 2014.  Optimization of development programs.  Test new ventures. 48
  • Appendix 49
  • 2014 Capital Budget $65 ($ in millions) $200 Development New Ventures Non Drilling 2014 capital budget of ~$1.9 billion Other $60 $1,660  Focused EFS and Bakken programs account for 75% of development budget.  Over 75% of development capital is allocated to projects operated by SM Energy. East Texas $55 PRB $140 Operated Eagle Ford $650 NonOperated Eagle Ford $250 Permian Shales $155 Bakken / Three Forks $350 50
  • Condensate Update South Texas & Gulf Coast % Oil Realization to LLS $50 90% $45 80% 70% 81% 85% 88% 86% 86% $35 60% 50% $40 $30 $21.33 $25 $19.64 40% $20 30% $15 $10.63 20% $4.18 10% $3.58 0% $10 $5 $0 4Q12 1Q13 2Q13 3Q13 4Q13 LLS Premium to WTI (Blue line) SM Oil Realization % of LLS 100%  Substantially all of SM Energy’s Eagle Ford condensate trades off of an LLS benchmark.  The Company’s condensate realization has remained stable as a percentage of the LLS benchmark.  SM Energy has approximately 10,0000 Bbls/d of firm condensate sales contracts utilizing a mixture of fixed and floating gravity differentials. 51
  • 4Q13 Regional Realizations Benchmark NYMEX WTI OIL (Bbl) Hart Composite NGL (Bbl) NYMEX Henry Hub Gas (MMBTU) $ $ $ Production Volumes Oil (MBbls) Gas (MMcf) NGL (MBbls) MBOE Revenue (in thousands) Oil Gas NGL Total Expenses LOE Transportation Production Taxes Per Unit Metrics: Realized Oil/Bbl % of Benchmark – WTI Realized Gas/Mcf % of Benchmark - NYMEX HH Realized NGL/Bbl % of Benchmark – HART Realized BOE LOE/BOE Transportation/BOE Production Tax - % of Total Revenue * Totals may not sum due to rounding. 97.41 43.13 3.82 STGC 1,449 27,442 2,813 8,836 $ Rockies 1,699 1,708 5 1,989 $ $ 125,710 101,878 108,718 336,306 $ $ $ 19,319 71,299 6,518 $ $ $ $ $ $ Mid-Con 113 9,285 75 1,735 $ $ 142,958 10,523 282 153,763 $ $ $ 20,417 1,558 15,518 86.74 89 % 3.71 97 % 38.64 90 % 38.06 $ 2.19 8.07 1.9 % $ $ $ $ $ Permian 493 1,064 0 671 $ $ 9,895 37,268 2,789 49,953 $ $ $ 84.15 86 % 6.16 161 % 56.42 131 % 77.32 $ 10.27 0.78 10.1 % $ $ $ $ $ SM Total 3,756 39,499 2,894 13,233 $ $ 46,070 7,391 8 53,468 $ 324,810 157,060 111,798 593,667 8,354 2,163 1,401 $ $ $ 12,886 32 3,108 $ $ $ 61,152 75,052 26,550 87.77 90 % 4.01 105 % 37.08 86 % 28.78 $ 4.81 1.25 2.8 % $ $ $ $ $ 93.42 96 % 6.95 182 % 32.09 74 % 79.73 $ 19.21 0.05 5.8 % $ $ $ $ $ 86.48 89 % 3.98 104 % 38.63 90 % 44.86 4.62 5.67 4.5 % 52
  • BAKKEN/THREE FORKS OPERATED RAVEN/BEAR DEN DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) Oil Type Curve 1,000 b factor Di (%) Dt (%) 671 1.4 80 8 Three Forks 1,200 30 Day IP (Bopd) Bakken 1,400 542 1.5 80 8 800 BKN TYPE CURVE 600 TFS TYPE CURVE 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS Gross EURs IRR Sensitivity Operating Costs Bakken 4.90 5.60 100% 11 80% 438 375 NGL (MBbl) - - Gas (MMcf)* 543 416 Ownership Total (MBOE) 529 444 Avg. Working Interest ~ 55% Avg. Royalty Burden ~ 17% Gross Capital Costs/ Well ($MM) Total Drill & Case $3.5 Total Complete $5.5 Total Capital $9.0 *Gas EUR values are net of fuel usage (10%) Production Tax (%) % IRR Oil (MBbl) Three Forks Op Costs ($/BOE) THREE FORKS 60% 40% 20% Differentials 0% Oil (% of WTI) Gas (% of HENRY HUB) 156% $80 92% NGL (% of WTI) BAKKEN - $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. Economics include shrink for field usage 53
  • THREE FORKS OPERATED GOOSENECK DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 900 800 Oil Type Curve 30 Day Max IP (Bopd) b factor Di (%) Dt (%) 700 Three Forks 324 1.4 63 8 600 500 400 300 200 100 0 1 2 3 Gross EURs Oil (MBbl) 4 5 6 7 8 9 10 11 12 13 14 MONTHS Operating Costs 368 Op Costs ($/BOE) Production Tax (%) Gas (MMcf)* 172 Ownership Total (MBOE) 397 Avg. Working Interest ~ 67% Avg. Royalty Burden ~ 19% 17 18 19 20 Total Drill & Case $2.8 23 24 Total Complete $3.7 Oil (% of WTI) % IRR 20% 89% Total Capital $6.5 Gas (% of HENRY HUB) 40% Differentials 116% *Gas EUR values are net of fuel usage (22%) 22 60% Gross Capital Costs/ Well ($MM) NGL (% of WTI) 21 80% 11 - 16 IRR Sensitivity 2.06 NGL (MBbl) 15 - THREE FORKS 0% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. EUR values are at the wellhead, economics include shrink for field usage 54
  • Operated Bakken/Three Forks Resource Potential Gooseneck Three Forks Raven/Bear Den Bakken Raven/Bear Den Three Forks 36,207 43,185* 43,185* EUR/well (MBOE) ** 397 529 444 Spacing (ac/well) 320 320 320 DCC/well ($MM) 6.5 9.0 9.0 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP 46 / 34 7.9 55 / 36 8.6 22 / 13 3.7 PUD 40 / 29 9.2 45 / 28 10.8 11 / 8 3.0 Total Proved 86 / 63 17.1 100 / 64 19.4 33 / 21 6.7 Unproved 64 / 41 12.3 55 / 32 11.0 110 / 64 20.0 Remaining Drilling Locations 104 / 70 21.5 100 / 60 21.8 121 / 72 23.0 * Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent. ** Gas EUR values are net of fuel usage 55
  • Non-Operated Bakken/Three Forks Resource Potential Gooseneck Three Forks Raven/Bear Den Bakken Raven/Bear Den Three Forks 36,207 43,185* 43,185* EUR/well (MBOE) ** 367 529 444 Spacing (ac/well) 320 320 320 DCC/well ($MM) 6.5 9.0 9.0 93 / 7 / 0 83 / 17 / 0 84 / 16 / 0 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP 4 / 0.5 0.1 76 / 14 3.5 36 / 5 1.4 PUD 0/0 0.0 56 / 12 5.0 16 / 2 0.9 Total Proved 4 / 0.5 0.1 132 / 26 8.5 52 / 7 2.3 Unproved 31 / 5 1.1 223 / 20 7.8 297 / 38 12.7 Remaining Drilling Locations 31 / 5 1.1 279 / 32 12.8 313 / 40 13.6 * Bakken and Three Forks are stacked formations and accordingly, the acreage figures for the two formations share the same aerial extent. ** Gas EUR values are net of fuel usage 56
  • Operated Eagle Ford Type Curve Regions Area 6 Area 1 Area 4 Area 3A Area 2 Area 5 Area 3B Area 5 57
  • OPERATED EAGLE FORD AREA 1 DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 800 700 Gas Type Curve 30 Day IP (Mcfpd) b factor Di (%) Dt (%) 600 AREA 1 1,423 1.5 69 10 500 6,500' Lateral 400 300 5,000' Lateral 200 100 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 * All values based on 6,500’ lateral. Gross EURs MONTHS Operating Costs Oil (MBbl) 106 Op Costs ($/BOE) NGL (MBbl) 174 Production Tax (%) Gas (MMcf) 1,164 Total (MBOE) 475 Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Total Complete $5.7 Total Capital $7.3 IRR Sensitivity 10.60 30% 3 25% Ownership Avg. Working Interest ~ 97% Avg. Royalty Burden % IRR 1 ~ 22% 20% 15% 10% 5% Differentials Oil (% of WTI) Gas (% of HENRY HUB) 108% NGL (% of WTI) 43% 0% 94% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 58
  • OPERATED EAGLE FORD AREA 2 Type Curve (1st 24 Months) DAILY EQUIVALENT PRODUCTION (BOEPD) 1,400 Gas Type Curve b factor Di (%) Dt (%) AREA 2 1,200 30 Day IP (Mcfpd) 3,829 1.2 75 10 1,000 800 6,500' Lateral 600 5,000' Lateral 400 200 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS * All values based on 6,500’ lateral. Gross EURs Operating Costs Oil (MBbl) 73 Op Costs ($/BOE) NGL (MBbl) 228 Production Tax (%) Gas (MMcf) 1,778 Total (MBOE) 597 Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Total Complete $6.2 Total Capital $7.8 IRR Sensitivity 10.76 60% 2 50% 40% Ownership Avg. Working Interest ~ 100% Avg. Royalty Burden % IRR 1 ~ 25% 30% 20% 10% 0% Differentials Oil (% of WTI) Gas (% of HENRY HUB) 107% NGL (% of WTI) 44% $80 94% $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 59
  • OPERATED EAGLE FORD – AREA 3A DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Gas Type Curve 2 3 Gross EURs 4 5 6 7 8 9 10 11 12 13 MONTHS Operating Costs 115 Op Costs ($/BOE) NGL (MBbl) 391 Production Tax (%) Gas (MMcf) 4,564 Ownership Total (MBOE) 1,266 Avg. Working Interest ~ 100% Avg. Royalty Burden 10.38 2 Di (%) Dt (%) 5,169 1.0 55 10 15 16 17 18 19 20 21 22 23 24 IRR Sensitivity ~ 25% 200% 150% % IRR Oil (MBbl) 14 b factor AREA 3 1 30 Day IP (Mcfpd) 100% 50% Gross Capital Costs/ Well ($MM) 0% Total Drill & Case $1.8 Differentials Total Complete $5.0 Oil (% of WTI) 94% Total Capital $6.8 Gas (% of HENRY HUB) 104% NGL (% of WTI) 40% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 60
  • OPERATED EAGLE FORD – AREA 3B DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Gas Type Curve 2 3 4 5 6 7 8 9 10 Gross EURs Oil (MBbl) 33 NGL (MBbl) 387 Production Tax (%) Gas (MMcf) 4,515 1,172 Avg. Working Interest ~ 100% Avg. Royalty Burden Dt (%) 5,169 1.0 55 10 15 ~ 25% Total Drill & Case $1.8 Total Complete $5.0 Total Capital $6.8 10.92 17 18 19 20 21 22 23 24 100% 1 80% % IRR Gross Capital Costs/ Well ($MM) 16 IRR Sensitivity Ownership Total (MBOE) 14 Di (%) Operating Costs Op Costs ($/BOE) 11 12 13 MONTHS b factor AREA 3 1 30 Day IP (Mcfpd) 60% 40% 20% Differentials 0% Oil (% of WTI) Gas (% of HENRY HUB) 104% NGL (% of WTI) 40% $80 94% $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 61
  • OPERATED EAGLE FORD AREA 4 DAILY EQUIVALENT PRODUCTION (BOEPD) Type Curve (1st 24 Months) 900 800 Gas Type Curve 30 Day IP (Mcfpd) b factor Di (%) Dt (%) 700 AREA 4 1,932 1.5 68 10 600 6,500' Lateral 500 400 5,000' Lateral 300 200 100 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MONTHS * All values based on 6,500’ lateral. Operating Costs Oil (MBbl) 130 Op Costs ($/BOE) NGL (MBbl) 254 Production Tax (%) Gas (MMcf) 1,834 Total (MBOE) 690 IRR Sensitivity 10.47 40% 2 30% Ownership Avg. Working Interest ~ 100% Avg. Royalty Burden % IRR Gross EURs ~ 21% Gross Capital Costs/ Well ($MM) Total Drill & Case $1.6 Differentials Total Complete $5.8 Oil (% of WTI) 94% Total Capital $7.4 Gas (% of HENRY HUB) 107% NGL (% of WTI) 43% 20% 10% 0% $80 $85 $90 $95 $100 $105 $/BBL - NYMEX Oil • Assumes natural gas price of $4.50/MMbtu & NGL price equal to 45% of crude oil price. 62
  • Operated Eagle Ford Resource Potential AREA 1 AREA 2 AREA 3A AREA 3B 35,082 21,879 22,226 29,726 EUR/well (MBOE) 475 597 1,266 1,172 Spacing (ac/well) 67 - 93 134 103 103 DCC/well ($MM) 7.3 7.8 6.8 6.8 22 / 41 / 37 12 / 50 / 38 Acreage (ac) Product Mix (O/G/NGL) 9 / 60 / 30 3 / 64 / 33 Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP* 49 / 49 5.9 26 / 26 9.9 95 / 95 51.5 39 / 39 15.8 PUD 8/8 2.7 36 / 36 22.8 79 / 79 70.6 46 / 46 31.0 57 / 57 8.6 62 / 62 32.7 174 / 174 122.1 85 / 85 46.8 Unproved 449 / 427 170.7 101 / 101 41.2 41 / 41 64.7 204 / 204 205.0 Remaining Drilling Locations 457 / 435 173.4 137 / 137 64.0 120 / 120 135.3 250 / 250 236 Total Proved * Includes PDN wells 63
  • Operated Eagle Ford Resource Potential AREA 4 AREA 5 AREA 6 8,268 25,124 1,560 EUR/well (MBOE) 690 931 617 Spacing (ac/well) 93 143 52 DCC/well ($MM) 7.4 7.3 7.9 19 / 44 / 37 0 / 78 / 22 35 / 35 / 30 Acreage (ac) Product Mix (O/G/NGL) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) Gross/Net Count Net Resource (MMBOE) PDP* 20 / 20 4.1 16 / 16 3.2 13 / 13 5.3 PUD 21 / 21 11.7 0/0 0.0 9/9 4.5 Total Proved 41 / 41 15.8 16 / 16 3.2 22 / 22 9.8 Unproved 48 / 48 33.9 159 / 159 130.7 8/8 4.8 Remaining Drilling Locations 69 / 69 45.6 159 / 159 130.7 17 / 17 9.3 * Includes PDN wells 64
  • EBITDAX Reconciliation EBITDAX (1) (in thousands) Reconciliation of net income (loss) (GAAP) to EBITDAX (non-GAAP) to net cash provided by operating activities (GAAP): Net income (loss) (GAAP) Interest expense Interest income Income tax expense (benefit) Depletion, depreciation, amortization, and asset retirement obligation liability accretion Exploration (2) Impairment of proved properties Abandonment and Impairment of unproved properties Stock-based compensation expense Derivative (gain) loss Cash settlement gain Change in Net Profits Plan liability Gain on divestiture activity EBITDAX (Non-GAAP) Interest expense Interest income Income tax expense (benefit) Exploration Exploratory dry hole expense Amortization of debt discount and deferred financing costs Deferred income taxes Plugging and abandonment Other Changes in current assets and liabilities Net cash provided by operating activities (GAAP) For the Three Months Ended December 31, 2013 2012 $6,996 ($67,138) 24,541 18,368 (3) (19) 8,755 (37,008) 202,640 204,267 20,105 15,778 110,935 170,400 5,046 37,646 6,852 8,454 11,605 (15,590) 9,347 11,461 (15,419) (11,562) (28,484) (4,228) $395,516 $298,229 ($24,541) ($18,368) 3 19 (8,755) 37,008 (20,105) (15,778) (32) 2,310 1,476 1,077 6,936 (36,943) (2,493) (1,052) (154) (379) (10,206) 2,260 $337,645 $268,383 (1) EBITDAX represents income (loss) before interest expense, interest income, income taxes, depreciation, depletion, amortization and accretion, exploration expense, property impairments, non-cash stock compensation expense, derivative gains and losses net of cash settlements, change in the Net Profit Plan liability, and gains and losses on divestitures. EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors, as a performance measure, for analysis of the Company's ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to financial covenants under its credit facility based on its debt to EBITDAX ratio. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by (used in) operating activities, profitability, or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. (2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration. 65
  • Adjusted Net Income Reconciliation Reconciliation of net income (loss) (GAAP) to adjusted net income (Non-GAAP): For the Three Months Ended December 31, (in thousands, except per share data) Reported Net Income (loss) (GAAP) 2013 $ 2012 6,996 $ (67,138) Adjustments net of tax: (1) Change in Net Profits Plan liability (9,683) (7,249) Derivative (gain) loss 7,288 (9,775) Derivative cash settlement gain 5,870 7,186 (17,888) (2,651) Impairment of properties 69,667 106,841 Abandonment and impairment of unproved properties 23,642 3,164 Gain on divestiture activity Adjusted net income (Non-GAAP): (2) $ 85,892 $ 30,378 Adjusted net income per diluted common share: $ 1.26 $ 0.45 Diluted weighted-average common shares outstanding: 68,354 66,906 (1) For the three-month period ended December 31, 2013, adjustments are shown net of tax and are calculated using a tax rate of 37.2%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. For the twelve-month period ended December 31, 2013, adjustments are shown net of tax using the Company's effective rate of 38.6%, as calculated by dividing income tax expense by income before income taxes shown on the consolidated statement of operations. For the three and twelve-month period ended December 31, 2012, adjustments are shown net of tax and are calculated using an tax rate of 37.3%, which approximates the Company's statutory tax rate adjusted for ordinary permanent differences. (2) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and generally are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash adjustments and impairments such as the change in the Net Profits Plan liability, derivative losses net of cash settlements, impairment of proved properties, abandonment and impairment of unproved properties, and (gain) loss on divestiture activity. The non-GAAP measure of adjusted net income is presented because management believes it provides useful additional information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted net income should not be considered in isolation or as a substitute for net income, income from operations, cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies. 66
  • 1Q14 Guidance 1Q14 FY 2014 12.0 – 12.6 51.0 – 53.5 133 – 140 140 – 147 LOE ($/BOE) $5.25 – $5.50 $5.25 – $5.50 Transportation ($/BOE) $5.75 – $6.05 $5.75 – $6.05 Production taxes (% of pre-derivative oil and gas revenue) 5.0% - 5.5% 5.0% - 5.5% G&A – Cash ($/BOE) $2.00 – $2.20 $2.20 – $2.45 G&A – Cash NPP ($/BOE) $0.20 – $0.35 $0.20 – $0.35 G&A – Non-cash ($/BOE) $0.35 – $0.50 $0.30 – $0.50 G&A Total ($/BOE) $2.55 – $3.05 $2.70 – $3.30 $15.10 – $15.90 $15.10 – $15.90 Production (MMBOE) Average daily production (MBOE/d) DD&A ($/BOE) Effective income tax rate range 37.0% – 37.5% % of income tax that is current <3% 67
  • Oil Derivative Position* Oil Swaps - NYMEX Equivalent Bbls Oil Swaps – WTI swap with LLS basis Differential $/Bbl 2014 Q1 Q2 Q3 Q4 2014 Total 2,175,000 2,373,000 973,000 891,000 6,412,000 $ $ $ $ 2015 Q1 Q2 Q3 Q4 2015 Total 820,000 896,000 615,000 580,000 2,911,000 $ $ $ $ 1,382,000 1,322,000 2,704,000 $ $ 85.19 85.19 Grand Total 425,000 425,000 Grand Total 12,027,000 96.13 94.95 95.25 95.16 2014 Q1 2014 Total $/Bbl 89.09 88.93 89.15 89.14 2016 Q1 Q4 2016 Total Bbls 425,000 $ 100.91 *As of 2/12/14 68
  • Oil Derivative Position* Oil Collars - NYMEX Equivalent Ceiling $/Bbl Bbls Floor $/Bbl 2014 Q1 Q2 Q3 Q4 2014 Total 694,000 431,000 973,000 923,000 3,021,000 $ $ $ $ 115.07 102.50 102.58 102.63 $ $ $ $ 80.97 85.00 85.00 85.00 2015 Q1 Q2 Q3 Q4 2015 Total 882,000 709,000 906,000 869,000 3,366,000 $ $ $ $ 99.53 94.06 91.25 92.19 $ $ $ $ 85.00 85.00 85.00 85.00 Grand Total 6,387,000 *As of 2/12/14 69
  • Gas Derivative Position* Natural Gas Swaps - NYMEX Equivalent MMBTU Natural Gas Collars - NYMEX Equivalent $/MMBTU 2014 Ceiling $/MMBTU MMBTU Floor $/MMBTU 2014 Q1 32,266,000 $ 4.24 Q1 1,540,000 $ 5.59 $ 4.40 Q2 23,758,000 $ 4.06 Q2 4,194,000 $ 5.41 $ 4.51 Q3 24,541,000 $ 4.10 Q3 - Q4 22,014,000 $ 4.13 2014 Total 102,579,000 2015 Q4 - 2014 Total 5,734,000 2015 Q1 17,342,000 $ 4.30 Q1 2,525,000 $ 4.41 $ 4.11 Q2 15,985,000 $ 4.06 Q2 2,297,000 $ 4.44 $ 4.14 Q3 14,950,000 $ 4.18 Q3 2,005,000 $ 4.44 $ 4.14 Q4 9,667,000 $ 4.18 Q4 6,176,000 $ 4.45 $ 4.12 2015 Total 57,944,000 2015 Total 13,003,000 Grand Total 18,737,000 2016 Q1 14,703,000 $ 4.42 Q2 9,130,000 $ 4.19 Q3 7,004,000 $ 4.26 Q4 6,635,000 $ 4.25 2016 Total 37,472,000 2017 Q1 6,299,000 $ Q2 5,974,000 $ 4.31 4.30 Q3 5,712,000 $ 4.30 Q4 5,445,000 $ 4.43 2017 Total 23,430,000 Note: Excludes volumes that were early settled in 1Q14 to unwind trades associated with Anadarko Basin properties sold on 12/30/13. The early settlement of these trades will result in a cash settlement gain of $5.6 million in 1Q14. 2018 Q1 5,203,000 $ 4.43 Q2 4,997,000 $ 4.43 2018 Total 10,200,000 Grand Total 231,625,000 *As of 2/12/14 70
  • NGL Derivative Position* Natural Gas Liquid Swaps - Mont. Belvieu Bbls 2014 Q1 Q2 Q3 Q4 1,429,000 1,096,000 960,000 861,000 2014 Total 4,346,000 Grand Total $/Bbl 4,346,000 $ $ $ $ 57.96 58.04 58.06 58.06 *As of 2/12/14 71