Sd november-2016-ir-presentation
- 2. CAUTIONARY STATEMENTS This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include statements about the company’s corporate strategies, future operations, development plans and appraisal programs, our drilling inventory and locations, estimated production, rates of return, reserves, projected capital expenditures, projected operating, general and administrative and other costs, anticipated efficiency and cost reduction initiative outcomes, the acquisition of seismic data, infrastructure utilization and investment, liquidity, capital structure, hedging position and strategies, and price realizations and differentials. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, and developing oil and natural gas reserves, the availability and terms of capital, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, regulatory changes and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A – “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 and in comparable “Risk Factors” sections of our Quarterly Reports on Form 10-Q filed after such Form 10-K. All of the forward-looking statements made in this presentation are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements. The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves, as each is defined by the SEC. At times we use the terms "EUR" (estimated ultimate recovery) and “recoverable reserves” that the SEC’s guidelines prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and, accordingly, are subject to substantially greater risk of being actually realized by the company. For a discussion of the company’s proved reserves, as calculated under current SEC rules, we refer you to the company’s amended Annual Report on Form 10-K referenced above, which is available on our website at www.sandridgeenergy.com and at the SEC’s website at www.sec.gov. 2 Forward Looking Statement www.sandridgeenergy.com
- 3. SANDRIDGE ENERGY With a strong balance sheet, we have competitive project IRRs from the high-graded harvest of our Mid-Continent position, plus we’re adding portfolio diversification and long term growth from our North Park Niobrara project, with capacity to do more. 3 www.sandridgeenergy.com
- 4. 4 SANDRIDGE ENERGY OVERVIEW DE-LEVERED OIL PRODUCER FOCUSED ON VALUE CREATION KEY INFORMATION PRIMARY ASSETS Mid-Continent Focus Area 458k Net Acres ~300 2P2 Locations North Park Basin Niobrara Oil 133k Net Acres ~1,300 2P2 Locations PRODUCTION & RESERVES Q3’16 Production 49.6 MBoepd3 (28% oil) Proved Reserves 281 MMBoe1 (25% oil) (1) SandRidge reserves and PV-10 pro forma for WTO divestiture and net of noncontrolling interests as of 12.31.15, based on SEC pricing at that time ($46.79 / $2.59) (2) 2P locations: Undeveloped Proved and Probable (3) Excludes production related to noncontrolling interests
- 5. THE REORGANIZED SANDRIDGE ENERGY AS OF OCT. 31ST 5 COMMON EQUITY MANDATORILY CONVERTIBLE DEBT $425MM REVOLVING CREDIT FACILITY $111MM CASH $536MMLiquidity • 20.6 MM common shares outstanding • 14.8 MM issuable upon conversion of mandatorily convertible debt • 4.9 MM warrants at $41.34 strike price • 2.1 MM warrants at $42.03 strike price • $278MM1 face value • Unsecured and mandatorily convertible into 14.8 MM shares • No interest2 • Undrawn3 • Minimal covenants or borrowing base redeterminations for two years • LIBOR (100 bps floor) + 475 bps rate • $111MM in unrestricted cash (1) $3.7 million par value converted as of October 31st (2) Make-Whole applicable if note accelerated following an event of default (3) Pro Forma for debt pay down following emergence and excludes approximately $10MM of LOCs Note: In addition to the items above there will be a $35MM note secured by the Company’s non-oil and gas real property net share settled
- 6. 6 OPERATIONAL HIGHLIGHTS & FULL YEAR CAPEX PLAN (1) A "lateral" is defined as a single one-mile section lateral whereas an “extended lateral” is defined as a two-mile lateral drilled across two sections, and a “multilateral” defined as two or more one-mile laterals drilled within a one-mile section (2) Calculated as the highest consecutive 30-Day average production rate during the early life of a well
- 7. 7 DURABLE IMPROVEMENT IN ECONOMICS MULTI AND EXTENDED LATERALS ARE A BREAKTHROUGH IN MISSISSIPPIAN D&C CAPEX, $MM PER LATERAL Lower costs per lateral -37% vs 2014 90-DAY CUMULATIVE MBOE PER LATERAL Results shown by groups of 50 wells
- 8. 8 • Stacked reservoirs combined with large acreage base • Appraising adjacent plays and additional zones • Miss Lime has been primary target – +/- 300’ thick carbonate at ~6,000’ TVD • Focus area concentrated within 458k net acres in OK • Over 1,600 horizontal wells drilled in OK & KS since 2010 • Salt water disposal infrastructure – 1,095 miles of pipeline, connected to 136 active disposal wells, injecting ~660 MBwpd • Electrical infrastructure – 1,250 miles of power lines, six substations and two micro grids • Field office is located in Alva, OK MID-CONTINENT OVERVIEW DIVERSE ASSET WITH FOCUS EXPANDING BEYOND MISSISSIPPIAN INTERVAL IN OKLAHOMA
- 9. • Nine Mississippian laterals drilled in 2016 with 36% IRR1, all multi or extended laterals • Projected average 2016 D&C Capex per lateral of $1.9MM • 1 dual extended lateral: (equivalent to 4 single laterals) • 1 full section development: (equivalent to 3 single laterals) • 1 coplanar: (equivalent to 2 single laterals) 9 MISSISSIPPIAN VALUE CREATION MULTI AND EXTENDED LATERALS PRESERVE COMPETITIVE RETURNS AT LOWER COMMODITY PRICES (1) Historical realized pricing + 11.2.16 NYMEX Strip and actual production + forecasted production
- 10. 10 • Single lateral $4.0MM D&C Capex for 315 MBoe EUR • Extended lateral projected $7.0MM D&C Capex ($3.5MM per lateral) for 600 MBoe EUR • Eleven laterals drilled in 2016; five laterals with over 90 days of production; three laterals in early evaluation phase and three brought online in Q4’16 • Successfully drilled first extended lateral (two mile lateral) • Averaged 3.3 MBopd the second half of October • 60 drilling permits approved • 28 MMBoe of proved reserves1 (81% oil); 108 PUDs • Stacked pay potential with over 1,300 2P locations • Large contiguous acreage position • Federal units largely eliminate near term HBP drilling requirements, ~75k net acres currently held by production or unit (56%) • Additional 33k net acres expected to be held by unit by year end 2017, for a total of ~108k net acres held by unit or production (81%) NORTH PARK NIOBRARA ASSET OVERVIEW DOMINANT ACREAGE POSITION WITH HIGH OIL CUT (1) SandRidge reserves as of 12.31.15, based on SEC pricing ($46.79 / $2.59)
- 11. 11 INITIALLY TARGETING LOWER NIOBRARA SIMILAR GEOLOGIC CHARACTERISTICS TO THE DJ BASIN NIOBRARA BUT HIGHER OIL CUT NORTH PARK BASIN DJ BASIN Oil EUR % 81% 35% - 40% Depth 5,500 – 9,000 ft. 6,000 – 8,000 ft. Reservoir Storage Capacity Gross Thickness Porosity 450 – 480 ft. 6 – 9% 150 – 300 ft. 6 – 10% OOIP per Section 63.8 MMBo 41.3 MMBo Thermal Maturity (Ro) 0.75 – 1.0% 0.5 – 1.4+% Reservoir Production Potential Reservoir Pressure Gas-oil Ratio (GOR) Total Organic Content > 0.55 psi/ft 600 – 700 scf/stb 3% 0.41 - 0.60 psi/ft Up to 10,000+ scf/stb 3%
- 12. 12 2016 SANDRIDGE NIOBRARA RESULTS 478 BOEPD (90% OIL) AVERAGE 30-DAY IP ON FIRST FIVE SANDRIDGE LATERALS DESIGNED TO TEST • Cycle time reduction • Extended lateral • Additional bench • Spacing • Stimulation methods • Artificial lift methods SIX LATERALS ONLINE IN LATE 2016FIRST FIVE SANDRIDGE LATERALS
- 13. 13 GREGORY 1-9H, 550 BOEPD (89% OIL) 30-DAY IP FIRST SANDRIDGE NIOBRARA LATERAL THE GREGORY 1-9H CONTINUES TO OUTPERFORM TYPE CURVE CUMULATIVE PRODUCTION OF 75 MBO AT 217 DAYS
- 14. 14 NIOBRARA TYPE CURVE SUPPORT AVERAGE OIL RATE OF FIRST FIVE SANDRIDGE LATERALS DRILLED FIRST 5 SANDRIDGE LATERALS • Outperforming type curve • Free flowed for over 3 months • Two of first five laterals placed on artificial lift • Will optimize production by accelerating artificial lift on future installations • Installing artificial lift on remaining 3 wells during November and December
- 15. 15 LAST 14 LATERALS USING MODERN COMPLETION DESIGNS 14 LATERALS SUPPORTING TYPE CURVE CUMULATIVE OIL
- 16. 16 NIOBRARA DRILLING ECONOMICS REDUCING COSTS $1MM PER LATERAL SUPPORTS LARGE IRR UPSIDE CURRENT COSTS ACHIEVED AFTER JUST 10 WELLS, WITH ONLY 1 EXTENDED LATERAL Assumptions: Single Laterals: $4.0MM D&C lateral cost, 315 MBoe EUR Extended Laterals $7.0MM D&C cost ($3.5MM per lateral), 600 MBoe EUR SINGLE LATERAL NOW $4MM PER LATERAL EXTENDED LATERAL NOW $3.5MM PER LATERAL REDUCING COST PER LATERAL OF EXTENDED LATERALS WILL BE A PRIORITY IN 2017
- 17. 17 ACHIEVABLE UPSIDE IN NIOBRARA LOWER COSTS, OPTIMIZED COMPLETIONS, EXTENDED LATERALS, STACKED PAY AND LOCATION COUNT HBP AND FEDERAL UNITS HOLD 56% OF ACREAGE UPSIDE INCLUDES • Successfully drilling extended laterals; first 2 mile lateral drilled and completed in Q3’16 and brought online in Q4’16 • Proving up additional benches – First SandRidge well, the Gregory 1-9H, producing from Upper and Lower Niobrara – Shallow Niobrara bench test well drilled in Q3’16; completed and brought online in Q4’16 • Expanding structural and geologic reservoir characterization model beyond existing 54 square miles of 3D seismic by acquiring additional 64 square miles of 3D seismic starting in 2017 • Optimizing completions to enhance production rate and ultimate recovery, while reducing costs • Reducing drilling and completion costs through applied learnings and observing DJ Basin operators
- 18. 18 NIOBRARA ASSET MIDSTREAM STATUS WTI OIL DIFFERENTIAL REDUCED FROM $11+/BBL TO $3.15/BBL NORTH PARK BASIN POTENTIAL PIPELINE ROUTESCURRENT OIL AND GAS DISPOSITION • Building out field gathering infrastructure; centralized tank battery concept used for processing, storage and export • Oil trucked to market (centralized oil loading bay could handle 40 MBopd) • Gas combusted under appropriate permits MIDSTREAM STRATEGY • Reduce air emissions by removing liquids from gas stream with Mechanical Refrigeration Units (MRUs) • Gas reinjection being considered to reduce combustion volumes • Oil and gas pipelines under evaluation – Currently proceeding with engineering, permitting and right-of-way acquisition for oil and natural gas pipelines
- 19. INVESTMENT THESIS POST RESTRUCTURING 19 • High-graded harvest of our Mid-Continent asset – ~1,300 producing horizontal wells, 3D seismic and improved reservoir characterization – One rig active most of 2016 – Production decline moderating – Infrastructure in place • Industry leading well costs and innovative multilateral development • Mid-Continent position supports other zones and opportunities • Appraising adjacent plays and additional zones • Industry activity moving north and west towards our position • Growth in oil reserves and value per barrel via North Park Niobrara development – Drilling and completing with encouraging results – 1,300 proved and probable locations and significant PUD potential • Expand extended lateral program • Upside through more Niobrara benches, completion and spacing optimization and lower well costs • Net unlevered balance sheet1 and strong liquidity provides financial flexibility • ~$536MM liquidity – ~$111MM of unrestricted cash – Undrawn $425MM revolver2 • Minimal covenants or borrowing base redeterminations for two years (1) Excluding mandatorily convertible notes (2) Pro Forma for debt pay down following emergence and excludes approximately $10MM of LOCs HARVEST & APPRAISE MISSISSIPPIAN EXPERTISE PLUS ADJACENT PLAYS DIVERSIFY GROW OIL AND VALUE VIA NIOBRARA DE-LEVERED STRONG FINANCIAL POSITION
- 20. APPENDIX 20
- 21. 2016 OPERATIONAL GUIDANCE 21 TOTAL COMPANY PRODUCTION Oil (MMBbls) 5.4 - 5.5 Natural Gas Liquids (MMBbls) 4.1 - 4.3 Total Liquids (MMBbls) 9.5 - 9.8 Natural Gas (Bcf) 57.0 - 57.3 Total (MMBoe) 19.0 - 19.4 PRICING REALIZATIONS Oil (differential below WTI) $3.75 NGLs (realized % of WTI) 30% Gas (differential below Henry Hub) $0.50 COSTS PER BOE LOE $8.80 - $9.00 DD&A – oil & gas1 5.80 - 6.20 DD&A – other 1.40 - 1.45 Total DD&A $7.20 - $7.65 G&A – cash2 $3.70 - $3.90 % OF NET REVENUE Severance Taxes 2.00% - 2.25% Corporate Tax Rate 0% Deferral Rate 0% (1) May be materially affected at year end by application of Fresh Start accounting (2) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, shareholder litigation costs, restructuring costs, and other non-recurring items. Incentive compensation plan normalized to be consistent with prior year compensation plans. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. Information to reconcile this non- GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods.
- 22. 2016 CAPITAL EXPENDITURES GUIDANCE 22 CAPEX GUIDANCE DETAIL $MM Mid-Continent D&C $42.5 - $47.5 North Park D&C 55 – 60 Other - D&C1 25 Total Drilling & Completing $122.5 - $132.5 OTHER E&P Land, G&G and Seismic $10 - $15 Infrastructure2 20 – 22.5 Workovers 37.5 – 40 Capitalized G&A and Interest 25 Total Other E&P $92.5 - $102.5 NON E&P General Corporate $5 Total Capital Expenditures (excl. A&D and P&A) $220 - $240 CAPEX GUIDANCE $MM D&C $122.5 - $132.5 Other E&P $92.5 - $102.5 Total Exploration and Production $215 - $235 General Corporate $5 Total Capital Expenditures $220 - $240 LATERAL SPUDS GROSS NET Mid-Continent 26 21 North Park 11 11 Total Laterals 37 32 (1) 2015 Carryover, JV Penalty, Rig Penalty, Non-Op, SWD (2) Facilities - Electrical, SWD, Gathering, Pipelines
- 23. NEW SANDRIDGE CAPITAL STRUCTURE 23 www.sandridgeenergy.com $536 MM OF TOTAL LIQUIDITY DE-LEVERED BALANCE SHEET (1) Secured by mortgages on the Company's non-oil and gas real property (2) $3.7 million par value of conversions as of Oct 31st (3) Excludes approximately $10 million of letters of credit PRO FORMA CAPITAL STRUCTURE $MM DEBT AT PRINCIPAL VALUE AS OF JUN 30, 2016 RESTRUCTURING PRO FORMA AS OF OCT. 31, 2016 Secured Note1 $ - $ 35 $ 35 8.75% Second Lien Secured Notes due 2020 1,328 (1,328) - Unsecured Notes: 8.75% Senior Unsecured Notes due 2020 $ 396 $ (396) $ - 7.50% Senior Unsecured Notes due 2021 758 (758) - 8.125% Senior Unsecured Notes due 2022 528 (528) - 7.50% Senior Unsecured Notes due 2023 544 (544) - Sub-Total Unsecured Notes $ 2,225 $ (2,225) $ - Unsecured Convertible Notes: 8.125% Senior Unsecured Convertible Notes due 2022 $ 41 $ (41) $ - 7.50% Senior Unsecured Convertible Notes due 2023 47 (47) - Total Senior Debt $ 3,641 $ (3,606) $ 35 0.00% Mandatorily Convertible Senior Subordinated Notes2 - 278 278 Total Debt $ 3,641 $ (3,328) $ 313 Liquidity RBL Borrowing Base3 $ 500 $ (75) $ 425 RBL Available - 425 425 Cash 634 (523) 111 Total Liquidity $ 634 $ (98) $ 536
- 24. HEDGES 24 Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 Oil (MMBbls) Swap Volume 1.29 0.63 0.64 0.64 0.64 2.56 0.27 0.27 0.28 0.28 1.10 Swap $56.45 $51.45 $51.45 $51.45 $51.45 $51.45 $55.10 $55.10 $55.10 $55.10 $55.10 Natural Gas (Bcf) Swap Volume 10.92 7.20 7.28 7.36 7.36 29.20 Swap $2.86 $3.19 $3.19 $3.19 $3.19 $3.19 Natural Gas Basis (Bcf) Swap Volume 0.92 Swap (0.38)