Sm Energy Company · NYSE:SM
Sm Energy — Investor Presentation (June 2015)
32 slides from Sm Energy's investor presentation, Jun 15, 2015
Slide 1: June 2015 Presentation
June 2015 Presentation
Slide 2: Forward Looking Statements - Cautionary Language
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 project
Slide 3: Asset and Strategy Overview
Asset and Strategy Overview How SM Energy will differentially grow shareholder value Economic inventory(1) of approx. 1.0 BBOE in operated Eagle Ford and Bakken/Three Forks; nearly 20 times 2014 corporate production Potential to increase inventory by more than double without acquisitions o o Preserv
Slide 4: An Industry Leader
An Industry Leader o SM Energy is consistently a top-quartile performer on key debt-adjusted per share measures: Production Proved reserves EBITDA(X) Note: Data sourced from Bloomberg and calculated by Company. Peer group based on Scotia Howard Weil 2014 F&D Cost Study with enterprise values between
Slide 5: Strong Balance Sheet
Strong Balance Sheet o Total Debt – currently 1.7x TTM EBITDAX; expected to be ~2.3x at YE15 Liquidity – Borrowing base maintained at $2.4 billion Maturities – None until 2021 (ex-revolver) PRO-FORMA* DEBT MATURITIES AS OF MARCH 31, 2015 o o (in millions) $2,500 $2,000 $1,500 $1,000 $500 $0 2015 201
Slide 6: 2015 – Reducing Activity and Building WOC Inventory
2015 – Reducing Activity and Building WOC Inventory o Capital Expenditure budget for 2015 is $1.2 billion • Investment is primarily focused on Eagle Ford & Bakken/TFS 20 100 18 90 16 80 14 70 12 60 10 50 8 40 6 30 4 20 2 10 0 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Eagle Ford Bakken/Three
Slide 7: Driving Costs Down
DrivingCosts Down o 2015 capital budget assumed 15% - 20% service cost deflation by year-end. o Company-wide costs currently are in-line with assumptions. budgeted deflation • • Drilling costs currently down 10% - 20%. Completions costs currently down 20% - 25%. Operated Eagle Ford drill, complete,
Slide 8: Accretive Divestiture & Production Increase
Accretive Divestiture & Production Increase SM Energy has entered into agreements to divest its Mid-Continent assets. Approximately $320 MM in expected cash proceeds. Arkoma Basin package closed on 5/29/15; ArkLaTex package expected to close by 6/30/15. Mid-Continent assets generated 11.1 MBOE/d in
Slide 9: Operated Eagle Ford Program
Operated EagleFord Program ~144,000 total net acres Dimmit Webb TEXAS Net Production 100 80 60 40 20 0 2009 2010 2011 2012 2013 2014 MBOE/d 9
Slide 10: Operated Eagle Ford – East
OperatedEagleFord– East Strong asset continues to provide top-tier returns. IRR Sensitivity(1) 70% 60% 50% 40% 30% 20% 10% 0% 100 90 80 70 60 50 40 30 20 10 0 $50 $60 NYMEX WTI $70 1 3 5 7 911 13 15 17 19 21 23 Producing Month (1) Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction
Slide 11: Operated Eagle Ford – North
OperatedEagleFord– North Improved completions have enhanced this asset. IRR Sensitivity(1) 40% 30% 20% 60 10% 50 0% $50 $60 NYMEX WTI $70 40 30 20 10 0 1 3 5 7 911 13 15 17 19 21 23 Production Month (1) Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. (2) Ut
Slide 12: Operated Eagle Ford – South
OperatedEagleFord– South Wells in southern acreage provide an economic dry gas option. IRR Sensitivity(1) 60% 50% 40% 30% 20% 10% 0% 70 60 50 $3.00 $3.50 NYMEX Henry Hub $4.00 40 30 20 10 0 1 3 5 7 911 13 15 17 19 21 23 Producing Months (1) Represents 25% reduction from YE14 well costs. (2) Utilizes
Slide 13: Thick Total Eagle Ford Shale Interval
Thick Total Eagle Ford Shale Interval o Identified several targets within the Upper and Lower Eagle Ford. Opportunity for increased inventory through stacking laterals. Testing Plan o o • • • Prove economic viability of UEF Optimize spacing Maximize recovery through stack/stagger 13 Austin Chalk Upp
Slide 14: Upper Eagle Ford East Testing
Upper Eagle Ford East Testing EAST UPPER EAGLE FORD WELLS CUMULATIVE BOE PRODUCTION 50 45 40 35 30 25 20 15 10 5 0 0 2 4 6 Producing Months 8 10 12 Galvan Ranch B311H (Upper EF) East Area Type Curve Galvan Ranch C314H (Upper EF) 14 2-STREAM CUMLATIVE PRODUCTION (MBOE/1000’) Upper Eagle Ford East res
Slide 15: Upper Eagle Ford North Testing
Upper Eagle Ford North Testing NORTH UPPER EAGLE FORD WELLS CUMULATIVE BOE PRODUCTION 45 40 35 30 25 20 15 10 5 0 0 2 4 6 Producing Months 8 10 12 Briscoe Catarina East 25H (Upper EF) North Area Type Curve Galvan Ranch LP GU5 State 20H (Upper EF) 15 2-STREAM CUMULATIVE PRODUCTION (MBOE/1000’) Upper
Slide 16: Stack/Stagger Testing Road Map
Stack/Stagger Testing Road Map infill spacing test (625’ LEF “W” test 16 Successful stack/stagger development of the Eagle Ford could more than double the current inventory of ~1,050 locations. 5 well LEF/UEF “W” test 3Q15 completion 2 well 2Q15 completion 3 well stacked/staggered 3Q15 completion 15
Slide 17: Eagle Ford North Stack/Stagger Pilot
Eagle Ford North Stack/Stagger Pilot Upper and Lower EF development well spacing in targeted facies AD ~70’ 525’ 263’ 262’ 525’ 525’ 17 ~175 ft ~200 ft Austin Chalk Upper Eagle Ford 1 P 1 PAD~120’ ~120’ ~85’ ~85’Lower Eagle Ford
Slide 18: Williston Basin Program
Williston Basin Program Net Production 20 15 10 5 0 2009 2010 2011 2012 2013 2014 MBOE/d Dunn acreage: ~245,000 18 Sh eridanDivide North Dakota Gooseneck: ~120,000 net acresWilliams Raven/Bear Den: Roosevelt~40,000 net acres McKenzie Total Williston Basin net acresBillings
Slide 19: Raven/Bear Den – Bakken
Raven/Bear Den – Bakken IRR Sensitivity(1) 50% 40% 30% 20% 10% 25 0% 20 $50 $60 NYMEX WTI $70 15 10 5 0 1 3 5 7 9 11 13 1517 19 21 23 Producing Month (1) Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction from YE14 well costs. (2) Utilizes assumptions from IRR sensitivity using $65
Slide 20: Gooseneck – Three Forks
Gooseneck–ThreeForks Substantial remaining inventory in our most economic Williston program. IRR Sensitivity(1) 50% 40% 30% 20% 16 10% 14 0% 12 $50 $60 NYMEX WTI $70 10 8 6 4 2 0 1 3 5 7 911 13 15 17 19 21 23 Producing months (1) Assumes $3.50/mmbtu gas, 40% WTI NGL realizations, and 25% reduction f
Slide 21: Gooseneck Sweet Spot
GooseneckSweetSpot Sizeable acreage position in the sweet spot of Divide County, ND reservoir quality reservoir quality o The geology deteriorates as activity moves east and west from the center section of Divide County. •Decreasing thermal maturity •Increasing water cut 21 Sheridan, MT DivideBurke
Slide 22: Outperforming Offset Operators
Outperforming Offset Operators Gooseneck Three Forks program vs. offset operators 16 14 12 10 8 6 4 2 0 1 3 5 7 9 11 13 15 17 19 21 23 PRODUCING MONTHS Offset Operator Results Three Forks Type Curve 22 CUMULATIVE PRODUCTION (MBOE/1000FT)
Slide 23: Proving up the Bakken in Gooseneck
Proving up the Bakken in Gooseneck Bakken wells in Gooseneck are outperforming the Three Forks type curve. 8 7 6 5 4 3 2 1 0 0 1 2 3 4 5 6 PRODUCING MONTHS Three Forks Type Curve Bakken Well Results 23 CUMULATIVE PRODUCTION (MBOE/1000FT) Successful development of the Gooseneck Bakken has the potenti
Slide 24: Takeaways
Takeaways o o o Top quartile performer Strong balance sheet Decades of economic inventory in two basins with potential to more than double Focus on creating shareholder value outperforming the peer group and o 24
Slide 25: Appendix
Appendix 25
Slide 26: NGL Realizations
NGL Realizations • Nominal revenue impact expected from recent NGL price declines •~$25 million or 1.5% of total 2015 budgeted revenue.(1) •2Q15 NGL realized price is expected to be similar to 1Q15. SM Energy’s NGL price realizations are predominantly tied to Mont Belvieu • • • Fee-based contracts.
Slide 27: 1st Quarter 2015 Performance
1st Quarter 2015 Performance • Production better than forecast due to strong Eagle Ford program performance; sequential production growth of 6%. • Outperformance to guided costs offset by weaker price realizations. • Pace of activity consistent with budget and service costs falling as anticipated. O
Slide 28: 1st Quarter 2015 Performance Reported Costs
1st Quarter 2015 Performance Reported 28 Costs LOE ($/BOE) Ad Valorem ($/BOE) Transportation ($/BOE) Production taxes (% of pre-derivative oil, gas, & NGL revenue) G&A --Cash ($/BOE) G&A --Non-cash ($/BOE) TOTAL G&A ($/BOE) DD&A ($/BOE) $3.96 $0.52 $6.08 4.8% $2.34 $0.26 $2.60 $12.96 Production1Q15
Slide 29: 2015 Guidance
2015 Guidance FY 2015 Production (MMBOE) 60.4 – 63.5 Average daily production (MBOE/d) 165 – 174 LOE ($/BOE) $4.40 – $4.65 Ad Valorem ($/BOE) $0.50 – $0.55 Transportation ($/BOE) $6.25 – $6.55 Production taxes (% of pre-derivative oil and gas revenue) 4.5% – 5.0% G&A – Cash ($/BOE) $2.50 – $2.80 G&A
Slide 30: 1Q15 Regional Realizations
1Q15 Regional Realizations 30 * Totals may not sum due to rounding. Per Unit Metrics: $37.59$38.30$40.85$43.42$38.56 77 %79 %84 %89 %79 % $2.84$2.00$2.46$3.22$2.76 99 %70 %86 %112 %96 % $16.71$17.43$3.46$27.78$16.67 78 %81 %7 %129 %77 % $20.82$34.48$15.05$36.86$23.44 $1.92$9.77$4.40$15.43$3.96 $0.62
Slide 31: Adjusted Net Income Reconciliation
Adjusted Net Income Reconciliation Reconciliation of net income (loss) (GAAP) to adjusted net income (Non-GAAP): For the Three Months Ended March 31, (in thousands, except per share data) Reported Net Income (loss) (GAAP) Adjustments net of tax: (1) Change in Net Profits Plan liability Derivative (g
Slide 32: Adjusted EBITDAX Reconciliation
Adjusted EBITDAX Reconciliation Adjusted EBITDAX (1) (in thousands) Reconciliation of net income (GAAP) to Adjusted EBITDAX (non-GAAP) to net cash provided by operating activities (GAAP): For the Three Months Ended March 31, 2015 2014 Net income (GAAP) Interest expense Other non-operating income, ne