SM Energy Company · NYSE:SM
SM Energy — Investor Presentation (November 2015)
46 slides from SM Energy's investor presentation, November 2015
Slide 1: Clear and Credible Path
November 2015 Clear and Credible Path
Slide 2: Forward Looking & Other Cautionary Statements
Forward Looking & Other Cautionary Statements This presentation contains 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”
Slide 3: Why SM Energy
Why SM Energy • Top-tier performer in debt-adjusted per share growth • Strong balance sheet • Decades of current economic inventory, with significant inventory growth potential without acquisitions or dilution OPERATING AREAS Williston Basin -Bakken/Three Forks Enterprise Value: ~$5 billion* 2014 Ye
Slide 4: Industry leader in Debt-Adjusted Per Share Growth
Industry leader in Debt-Adjusted Per Share Growth Consistently a top-quartile performer: only 2 companies are top-tier in all categories 40% 60% 3 YR CAGR EBITDA(X)/DA share 3 YR CAGR Production/DA share 30% 50% 40% 20% 30% 10% 20% 0% 10% SM -10% 0% -10% SM -20% -20% -30% -30% -40% -40% -50% -50% 80
Slide 5: Top Tier Financial Position
Top Tier Financial Position Well positioned for 2016 • Current Debt:TTM Adjusted EBITDAX 1.9 times Financial Position • Ample liquidity with $0.2 B drawn on $1.5 B Commitments amount and $2.0 B Borrowing Base • No maturities until 2021 (excluding revolver) Debt Maturities as of September 30, 2015 (i
Slide 6: Economic Inventory Greater than 1 Billion BOE
Economic Inventory Greater than 1 Billion BOE Current Economic Inventory* in Operated Development Programs Williston Basin ~90 MMBOE (net) ~500 gross locations Midland Basin ~75 MMBOE (net) ~250 gross locations Eagle Ford ~900 MMBOE (net) ~1,050 gross locations * Economic inventory consists of proje
Slide 7: 3Q15 Highlights – Exceeding 2015 Expectations
3Q15 Highlights – Exceeding 2015 Expectations Key Messages: • EXECUTION – Faster drill times and better completions driving better wells and lower costs • PERFORMANCE – Production exceeding plan due to well performance and successful downspacing tests in high productivity areas • RESULTS DELIVER UPS
Slide 8: Performance: 3Q15 Outstanding Quarter
Performance: 3Q15 Outstanding Quarter Well performance and cost focus PRODUCTION* UP 30% YOY • 3Q Production – 16.1 MMBOE 200 180 160 175 174 175 Up 30% from 2014 on retained properties 140 165 MBOE/d and beating plan 120 100 134 80 • 3Q LOE - $3.86/BOE 60 40 Down 16% from 2014 and right at plan 20
Slide 9: 2015 Activity Reducing Rigs and Building DUC Inventory
2015 Activity Reducing Rigs and Building DUC* Inventory Capital budget of $1.28 billion, down 37% from 2014** 18 150 15 125 Drilled but Uncompleted Wells 12 100 Operated Rigs 9 75 6 50 3 25 0 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Eagle Ford Bakken/Three Forks Permian Other DUC* Inventory
Slide 10: High Quality Portfolio
High Quality Portfolio 2016 program is expected to offer growth with solid returns IRR Sensitivities to Oil Price* Eagle Ford East Bakken, Divide County Lower Spraberry 60% 60% 60% 50% 50% 50% 40% 40% 40% ** 30% 30% 30% 20% 20% 20% 10% 10% 10% 0% 0% 0% $50.00 $60.00 $70.00 $50.00 $60.00 $70.00 $50.0
Slide 11: Potential to Double Inventory on Existing Assets
Potential to Double Inventory on Existing Assets • Eagle Ford thick pay upside Potential to double Eagle Ford inventory through optimizing spacing and landing zones • Bakken interval in Divide County Geologic sweet spot with potential to double inventory • Additional intervals in Midland Basin Testi
Slide 12: Eagle Ford – World Class Asset
Eagle Ford – World Class Asset NORTH AREA Net Production (MBOE/d) 150 EAST AREA Mexico 100 MEXICO 50 MEXICO SOUTH AREA TEXAS 0 2009 2010 2011 2012 2013 2014 3Q15* Operated Non-operated *YTD through 3Q15 Operated Eagle Ford Non- operated Eagle Ford ~144,000 net acres ~36,000 net acres 12
Slide 13: Optimization – Eagle Ford Efficiency Gains
Optimization – Eagle Ford Efficiency Gains Average Drilling Cost Average Completion Cost per Lateral Foot per Lateral Foot $400 $1,000 $350 $800 $/Lateral Foot $/Lateral Foot $300 $250 $600 $200 $150 $400 $100 $200 $50 $0 $0 2014 2015 YTD 3Q15 2014 2015 YTD 3Q15 • Drilling cost per lateral foot down
Slide 14: Inventory Upside – Eagle Ford Pilot Test Progress
Inventory Upside – Eagle Ford Pilot Test Progress Testing underway to evaluate substantial potential upside from existing assets Pilot Tests: 1) East Area Down-spacing 14-well 625’ & 450’ spacing 2) East Area Infill LEF “W” 2-well down-spaced infill @ 625’ and 450’ 3) South Area LEF/UEF “W” 5-well L
Slide 15: Inventory Upside – Pilot Test #1 East Area 14-Wells
Inventory Upside – Pilot Test #1 East Area 14-Wells Testing 450’ spacing has potential to increase EF inventory by ~25% Pilot test area 15
Slide 16: Inventory Upside – PT#1 - 450' Spacing in East
Inventory Upside – PT#1 - 450’ Spacing in East Production results to date for 450’ spaced wells are in-line with 625’ spaced wells 160 Cum Gross Wet Gas Production (MMcf per 1000' Lateral Length) 140 120 100 80 60 40 20 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 Days on Production 16
Slide 17: Inventory Upside – PT #1 – Pressure Data Encouraging
Inventory Upside – PT #1 – Pressure Data Encouraging Flowing pressures of 450’ well spacing tests are greater than 625’ well spacing; no indication of interference 6,000 5,000 Avg Casing Pressure (psi) 4,000 3,000 2,000 1,000 0 0 100 200 300 400 500 600 700 800 900 Average Cum Gross Wet Gas Per Well
Slide 18: Inventory Upside – PT #3 – Facies & Testing
Inventory Upside – PT #3 – Facies 3 & 6 Testing Upper Eagle Ford Facies 7 GR C203H GR C205H Facies 6 145’ Facies 5 312’ 312’ 312’ 312’ Facies 4 Facies 3 Facies 2 GR C202H GR C204H GR C206H 145’ Lower Eagle Ford Facies 1 • Early data encouraging • Positive implications for development of high GOR are
Slide 19: Bakken/Three Forks – World Class Asset
Bakken/Three Forks – World Class Asset DIVIDE NORTH DAKOTA GOOSENECK ~120,000 net acres Net Production RAVEN / BEAR DEN 25 WILLIAMS ~40,000 net acres 20 15 ROOSEVELT 10 5 0 MCKENZIE 2009 2010 2011 2012 2013 2014 3Q15* DUNN MBOE/d *YTD through 3Q15 BILLINGS Total Williston Basin acreage: ~245,000 net
Slide 20: Geological Sweet Spot – Divide County
Geological Sweet Spot – Divide County Unique positioning among peers PhiH of Middle Bakken and Upper Three Forks Well results largely driven by: • Hydrocarbon charge – thermal maturity • Reservoir quality – PhiH (porosity & thickness) • Water Cut Immature (<430 Tmax) Water Cut 70% 70% 430 Tmax 20
Slide 21: Optimization – Bakken Drilling Efficiency Gains
Optimization – Bakken Drilling Efficiency Gains • Drilling days down 11% YOY and 34% from 2012 • Recent Divide County Bakken well drilled 17,750’ in 10 days • Drilling cost per foot down 22% YOY Average Days Spud to Rig Release 40 35 30 25 Days 20 15 10 5 0 2012 2013 2014 2015 Raven/BD Divide 21
Slide 22: Optimization – Bakken Completion Efficiency Gains
Optimization – Bakken Completion Efficiency Gains • Expect to maintain improved efficiency regardless of market conditions • Pad Development • “Zipper” fracs • Continuous execution improvement • Significant completions savings due to market and efficiency gains • 40% due to market changes • 60% due
Slide 23: Optimization – Plug-and-Perf Completions Improving Economics
Optimization – Plug-and-Perf Completions Improving Economics • Plug-and-perf completions have been employed by SM in both Divide County and Raven/Bear Den programs in the Williston Basin • Plug-and-perf results show uplift in IRR Divide County TFS results Divide TFS IRR Sensitivity* 18 60% ADJUSTED
Slide 24: Inventory Upside – Proving Up Bakken in Divide County
Inventory Upside – Proving Up Bakken in Divide County Bakken interval has the potential to double Divide County inventory NORTH DAKOTA • Bakken wells drill faster, therefore cheaper than Three Forks wells • The Company completed 2 Divide Bakken wells in October 2015 Middle Bakken Wells Recently Comp
Slide 25: Permian Sweetie Peck – More Economic Inventory
Permian Sweetie Peck – More Economic Inventory Prime location, significant value potential through proving up additional intervals TEXAS MIDLAND UPTON Net Acreage: ~15,000 • Predominantly 100% working interest contiguous position • More than 15,000 net acres with ~1,900’ of potential pay 25
Slide 26: Optimization – Midland Basin Shales
Optimization – Midland Basin Shales Landing zone and completion optimization drive well performance Focus on Landing Zone Improves ROP WOLFCAMP “B” COMPLETION Wolfcamp "B" Landing Zone Optimization OPTIMIZATION IMPROVES PRODUCTION Improves Well Performance 30 240 Day Cumulative Production (MBOE/1000
Slide 27: Optimization – SM Energy a Leader in Well Performance
Optimization – SM Energy a Leader in Well Performance Top Midland Basin IP Performance Wolfcamp B – Midland Basin 1,800 19 15 1 1,600 1 1,400 Normalized to 7500’ lateral length 24 Hr IP (BOEPD) 2 1,200 22 15 180 6 21 50 28 1,000 3 12 76 34 30 3 50 3 800 20 1 4 4 12 79 600 10 133 13 2 58 25 4 4 400 7
Slide 28: Looking Forward – Late 2015/2016
Looking Forward – Late 2015/2016 Focus on returns in low price environment • Expect to allocate increased portion of capital to oily programs • Permian • Divide County Bakken/Three Forks • Expect to start completing oily DUC wells in late 4th quarter with minimal impact on CAPEX spend in 2015 • Cont
Slide 29: Summary
Summary Another strong quarter Projected Debt:Adjusted EBITDAX* 2.2x est. YE2015 Ample current liquidity: ~$1.3 B Sustainable business plan at low product prices Potential to double economic drilling inventory from existing asset base * We cannot provide a reconciliation to the most direct
Slide 30: Appendix
Appendix
Slide 31: SM Energy at a Glance
SM Energy at a Glance Operations focused in Eagle Ford and Bakken/Three Forks • Enterprise Value*: ~$5 billion • 2014 Proved Reserves: 548 MMBOE • 2015e** Production: 64 MMBOE / ~175 MBOE/d • Current Inventory: ~20x 2014 Production • Debt:Adjusted EBITDAX*** at 1.9x (TTM) *As of October 23, 2015; **
Slide 32: 2015 Guidance
2015 Guidance Production FY 2015 Total Production (MMBOE) 63.6 – 64.4 Average daily production (MBOE/d) 174 – 176 Costs LOE ($/BOE) $3.70 - $3.90 Ad Valorem ($/BOE) $0.45 - $0.50 Transportation ($/BOE) $6.10 - $6.25 Production taxes (% of pre-derivative oil, gas & NGL revenue) 4.5% - 5.0% G&A – Cash
Slide 33: 3rd Quarter 2015 Performance
3rd Quarter 2015 Performance Production 3Q15 Total Production (MMBOE) 16.1 Average Daily Production (MBOE/d) 174.5 Pre-Hedge Realized Price ($/BOE) $22.84 Post-Hedge Realized Price ($/BOE) $29.92 Costs LOE ($/BOE) $3.86 Ad Valorem ($/BOE) $0.40 Transportation ($/BOE) $6.27 Production Taxes (% of pre
Slide 34: 3Q15 Regional Realizations
3Q15 Regional Realizations Pricing NYMEX WTI Oil (Bbl) 46.48 NYMEX LLS Oil (Bbl) 50.24 NYMEX Henry Hub Gas (MMBTU) 2.75 Hart Composite NGL (Bbl) 18.22 Production Volumes STGC Rockies Permian SM Total Oil (MBbls) 1,763 2,334 417 4,520 Gas (MMcf) 39,685 2,346 1,320 43,341 NGL (MBbls) 4,220 90 - 4,309
Slide 35: 2015 Activity – Wells Drilled, Flowing Completions & DUC Count
2015 Activity – Wells Drilled, Flowing Completions & DUC Count Wells Drilled Flowing Completions Drilled and Uncompleted 3rd Quarter 2015 Year-to-Date 2015 3rd Quarter 2015 Year-to-Date 2015 Year-to-Date 2015 Region Gross Net Gross Net Gross Net Gross Net Gross Net Eagle Ford Operated 28.0 28.0 84.0
Slide 36: Adjusted Net Income Reconciliation
Adjusted Net Income Reconciliation Reconciliation of net income (loss) (GAAP) to adjusted net loss (Non-GAAP): For the Three Months (in thousands, except per share data) Ended September 30, 2015 Reported Net income (GAAP) $3,114 Adjustments net of tax: (1) Change in Net Profits Plan liability (2,758
Slide 37: Adjusted EBITDAX Reconciliation
Adjusted EBITDAX Reconciliation Reconciliation of net income (GAAP) to Adjusted EBITDAX (non-GAAP) to net cash provided For the Three Months by operating activities (GAAP): (in thousands) Ended September 30, 2015 Net income (GAAP) $3,114 Interest expense 33,157 Other non-operating income, net (27) I
Slide 38: Hedging – Provides Cash Flow Stability
Hedging – Provides Cash Flow Stability • 45% of guided midpoint 4Q15 production volumes hedged • ~44% of 2016 production volumes hedged assuming forecasted 4Q15 production held flat into 2016 9 Hedged Volumes as of October 21, 2015 8 8.01 7 7.23 6.66 6 (MMBOE) 5.92 5 4.93 4 3 2 1 0 4Q15 1Q16 2Q16 3Q
Slide 39: Summary Derivative Positions – By Quarter Through 2016
Summary Derivative Positions – By Quarter Through 2016 as of October 21, 2015* Oil Gas NGL**** Volume Volume Volume Period (MBbls) $/Bbl** (BBTU) $/MMBTU** (MBbls) $/Bbl*** 4Q’15 2,006 $87.92 17,656 $4.07 1,709 $21.58 1Q’16 1,868 $86.93 23,341 $3.90 2,250 $15.67 2Q’16 1,752 $86.73 20,780 $3.39 2,018
Slide 40: Oil Derivative Position
Oil Derivative Position* Oil Swaps – NYMEX Equivalent Oil Collars – NYMEX Equivalent Period Volume (MBbls) $/Bbl Period Volume (MBbls) Ceiling $/Bbl Floor $/Bbl 4Q’15 1,137 $90.15 4Q’15 869 $92.19 $85.00 2015 Total 1,137 2015 Total 869 1Q’16 1,868 $86.93 Grand Total 869 2Q’16 1,752 $86.73 3Q’16 1,17
Slide 41: Gas Derivative Position
Gas Derivative Position* Natural Gas Swaps – NYMEX Equivalent Natural Gas Collars – NYMEX Equivalent Period Volume $/MMBTU Period Volume Ceiling Floor (MMBTU) (MMBTU) $/MMBTU $/MMBTU 4Q’15 12,499,000 $4.08 4Q’15 5,157,000 $4.36 $4.05 2015 Total 12,499,000 2015 Total 5,157,000 1Q’16 23,341,000 $3.90
Slide 42: NGL Derivative Position
NGL Derivative Position** NGL Swaps OPIS Eth Purity Mt Belv – NYMEX Equivalent NGL Swaps OPIS IsoButane Mt Belv Non TET– NYMEX Equivalent Period Volume (MBbls) $/Bbl* Period Volume (MBbls) $/Bbl* 1Q’16 926 $8.29 4Q’15 276 $25.30 2Q’16 828 $8.28 2015 Total 276 3Q’16 751 $8.70 1Q’16 122 $25.87 4Q’16 6
Slide 43: NGL Realizations
NGL Realizations • 3Q15 benefitted $0.94/Bbl from propane and butane hedges • SM NGL price realizations are predominantly tied to Mont Belvieu, fee-based contracts • Differential reflects NGL barrel product mix and transportation and fractionation fees • Macro picture indicates pricing pressure is e
Slide 44: Eagle Ford Peer Operators
Eagle Ford Peer Operators APC APC APC CHK APC SN Lewis SM EF North APC CHK NBL (ROSE) SM EF East SM EF South SFY Note: SM is a working interest partner in APC acreage with working interests that range from 12.5%-37.5% 44
Slide 45: Pilot Test #5: LEF/UEF Stack Stagger Co-Development
Pilot Test #5: LEF/UEF Stack Stagger Co-Development Triple the number of wells per section with multiple Eagle Ford landing zones 1 PAD ~120 ~120’ ’ ~85’ ~110’ ~85’ ~70’ 12-well North Area stack stagger test – expected completion at end of 3Q15 45
Slide 46: IR Contact
IR Contact: Jennifer Martin Samuels [email protected] 303-864-2507 Website: www.sm-energy.com 46
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