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SandRidge Feb 2017 IR Presentation
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- 2. Cautionary Statements This presentationincludes "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, operational optimization initiatives anticipated efficiency and cost reductions, the acquisition of seismic data, infrastructure investment, liquidity, capital structure, hedging position, 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 astrong balance sheet, we have built a portfolio of three project areas with competitive project IRRs and significant location inventories. Investment will continue the high-graded harvest of our Mississippian position, development of our NW STACK acreage, plus portfolio diversification and long term growth from our North Park Niobrara oil project, with capacity to do more. 3 www.sandridgeenergy.com - >$500MM of liquidity including ~$120MM cash - Moderate level of outspend - Protect the balance sheet - High-graded harvest - Competitive project IRRs - Continued cost reductions - Consistent well results - Well design innovation - Expands drilling inventory - 1,300 2P locations - Multiple benches and tighter spacing upsides - >80% oil resource - Main focus of 2017 Capex - Meramec & Osage - ~60k net acres in 3 counties • Major (30k net acres) • Woodward (20k net acres) • Garfield (10k net acres) - Increased oil exposure
- 4. 4 SandRidge Energy Overview Unleveredoil producer focused on resource value creation KEY INFORMATION Market Equity Value @ $21 / Share 35.9 MM common shares $754 Million Primary Assets 2P Locations1 Net Acres Mississippian Anadarko Basin, OK ~300 400k NW STACK Anadarko Basin, OK Under Evaluation 60k Niobrara Shale North Park Basin, CO ~1,300 132k Production & Reserves Q4’16 Production 47.2 MBoepd (28% oil) YE’16 Proved Reserves2 184 MMBoe (31% oil) $946MM Strip PV-10(1) 2P locations: Undeveloped Proved and Probable (2) SandRidge reserves and PV-10 as of 12.30.16 Strip pricing (~$56/$3.00). The PV-10 of strip-based proved reserves is a non-GAAP financial measure. A reconciliation of the standardized measure (GAAP) to the PV-10 of our proved reserves is located on the final slide.
- 5. 5 STACK Activity MovingNorthwest Increasing activity supports enthusiasm around Major, Woodward, and Garfield Co. NW STACK • Multiple operators with NW STACK Meramec and Osage results • 13 rigs currently running • Over 50 producing wells in Major, Woodward, and Garfield • More than 100 permitted wells in Major, Woodward, and Garfield INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE Industry activity has been converging on existing SD acreage with prominent operators seeing encouraging results:
- 6. 6 NW STACK PrimaryTargets NW STACK Meramec and Osage same productive formation as in STACK Structurally deepens from northeast to southwest Meramec 5,800’-12,400’ TVD • Below the Chester (where present) • Interbedded shales, sands, and carbonates • Thickness from 50’-160’ • Matrix porosity development in limey-sand zones with some secondary fracturing Lower Osage 5,900’-12,500’ TVD • Dense limestone and cherts • Thickness from 450’-1,300’ • Natural fracturing enhances productivity
- 7. 7 NW STACK –Meramec and Osage SandRidge has operated in and around the NW Stack for many years 2016 Meramec and Osage program • Medill 1-27H, Major Co., Meramec • Keeton 1-24H, Major Co., Osage • Charlene 1-29H, Garfield Co., Meramec Osage drilled in Garfield Co. in 2014-15 • Benkendorf and Henry wells average 30-Day IP of 618 Boepd (74% oil) Successful track record in Oklahoma • Operating in area for more than seven years developing nearby Miss Lime and Chester • Low cost operator, realizing as low as $1.3MM of D&C per lateral in Miss Lime • Over 1,600 wells drilled SANDRIDGE ACTIVITY ACROSS 3 COUNTIES
- 8. 8 Activity Proving OutNW STACK 13 Rigs running, many producing wells now near SD NW STACK acreage
- 9. 9 NW STACK Acquisition Acquisitionincreases our NW STACK position to 60k net acres • Complements surrounding SD NW STACK acreage • Stacked pay of Meramec and Osage • Adds locations with competitive IRRs at strip • ~700 Boepd of production • 88% operated w/ minimal near term acreage expiries CONTIGUOUS ~13.1K NET ACRES FOR $48MM CASH
- 10. Lateral $1.7MM Avg D&Cper • 1 dual XRL: (equivalent to 4 single laterals) • 1 full section development: (equivalent to 3 single laterals) • 1 coplanar: (equivalent to 2 single laterals) • 2 XRLs: Record low of $1.3MM Avg D&C (equivalent to 4 single laterals) 10 High-Grade + Innovation = Value Creation 2016 Mississippian program: 13 laterals, 51% IRR1 (1) Estimated based on historical realized pricing + 2.10.17 NYMEX Strip and actual production + forecasted production 100% Multi and XRL
- 11. 11 Durable Improvement inMississippian Economics Multis and XRLs support continued harvest of remaining high-graded inventory D&C CAPEX, $MM PER LATERAL 43% Lower costs per lateral vs. 2014 90-DAY CUMULATIVE MBOE PER LATERAL Results shown by groups of 25 wells
- 12. 12 Mississippian Recoveries Improving High-gradedharvest resulting in more consistent results • High-grading results in improving EUR trend • Realizing tighter EUR distributions (P10 / P90) • Remaining Mississippian locations form reliable inventory P10 / P90 RATIO 2013 2014 2015 2016 7 7 6 2 PROJECTED EURS NORMALIZED BY LATERAL
- 13. 13 • XRLs currentlybelow $7.0MM D&C (<$3.5MM per lateral) with projected 600 MBoe EUR and targeting sub-$3.5MM per lateral in 2017 • Ten wells drilled in 2016 including one XRL and one “C” bench target • 60 drilling permits approved • 30 MMBoe of proved reserves1 (87% oil) • Federal units largely eliminate near term HBP drilling requirements, 71k net acres currently held by production or unit (54%) North Park Niobrara Asset Overview Dominant acreage position with high oil cut (1) SandRidge reserves as of 12.31.16, based on SEC pricing ($42.75 / $2.48) • 1,300 2P Locations • 132k Net acres
- 14. 14 Initially Targeting LowerNiobrara Similar geologic characteristics to the DJ Basin Niobrara but higher oil cut NORTH PARK BASIN DJ BASIN Oil EUR % >80% ~35% 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%
- 15. 15 SandRidge Niobrara ShaleAdvancements Lowered costs, optimized completions, drilled an XRL, confirmed stacked pay Improved drilling and completion designs • Eliminated intermediate casing • Oil based mud utilized for improved drilling times and hole stability • Confirmed crosslinked gel fracs yield consistent well results; seven crosslink gel wells above type curve • Slickwater fracs led to lower initial oil rates and higher water cuts due to large volume of water pumped Drilled the first XRL in the basin • 2-mile lateral drilled and completed for $3.4MM D&C per lateral with a 30-Day IP of 901 Boepd (91% oil) Proved up additional Niobrara benches • Niobrara “C” bench test (Hebron 4-18H) resulted in second highest highest per lateral 30-Day IP at 539 Boepd (92% oil) • Nine additional wells targeted the “D” bench
- 16. 16 North Park LateralsOutperforming Cumulative Oil Type Curve 11 SandRidge Laterals in 2016 outperforming type curve by 9%
- 17. 17 North Park LateralsOutperforming Oil Type Curve Average oil rate of all 11 laterals drilled by SandRidge in 2016 11 SD Laterals in 2016: • Average free flowing period of two to three months • Earlier installation of artificial lift in future to optimize production • All laterals currently on either jet pump, gas lift, or rod pump lift mechanisms
- 18. 18 Niobrara Asset MidstreamStatus Oil currently trucked at low differential to WTI NORTH PARK BASIN POTENTIAL PIPELINE ROUTESCurrentOil and Gas Disposition • Building out field gathering infrastructure; centralized tank battery used for processing, storage and export • Oil trucked to market (centralized oil loading bay could handle 40 MBopd) • Gas combusted under appropriate permits Strategic Options • Removing liquids from gas stream • Oil and gas pipelines under evaluation • Currently proceeding with engineering, permitting and right-of-way acquisition for oil and natural gas pipelines • Gas reinjection being considered to reduce combustion volumes
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- 20. 20 2017 Project EURs,Economics, & Inventory EURs & Economics Meramec Niobrara Mississippian XRL* Single XRL FSD* Single EUR, MBoe % Oil 800 – 1,000 40% 500 – 600 40% 600 85% 1,350 20% 550 20% D&C per lateral ($MM) $3.1 $4.2 $3.4 $2.0 $2.4 IRR(a) 24 - 42% 19 - 31% 33% 65% 17% PV-10(a) ($MM) $2.4 - $4.7 $1.0 - $2.1 $3.4 $5.5 $0.5 YE’16 Inventory NW STACK Niobrara Mississippian PUDs (laterals) 6 106 51(b) Probables (laterals) Under evaluation (4-8 per section is standard) ~1,180 ~180(b) Net acres 60k 132k 400k HBP 27% 54% 74% a) @ Feb 10th Strip pricing (~$55 /~$3.00) b) Excluding ~70 Proven + Probable Chester locations Diverse and material location inventory in three active areas *FSD = “Full Section Development”, equivalent to 3 laterals *XRL = “Extended Reach Lateral”, 2-mile lateral
- 21. Year End 2016Reserves and PV-10 21 Proved Reserves Oil MBbls NGLs MBbls Gas MMcf Equivalent MBoe1 PV-102 $MM Proved Reserves as of Dec 31, 2015 @ SEC Pricing ($50.28 / $2.59) 77,911 61,075 1,113,840 324,626 $1,315_ Production (5,529) (4,357) (56,895) (19,369) Sale of assets (387) 0 (145,267) (24,598) Change in accounting for trusts (6,971) (3,695) (50,508) (19,084) Performance revisions (14,796) (21,717) (349,244) (94,720) Pricing revisions (1,510) 876 (68,865) (12,112) Extensions & additions 4,166 1,425 21,720 9,210 Proved Reserves as of Dec 31, 2016 @ SEC Pricing ($42.75 / $2.48) 52,884 33,607 464,782 163,955 $438_ Proved Reserves as of Dec 31, 2016 @ NYMEX Pricing (~$56 / ~$3) 56,338 38,662 535,494 184,250 $946_ (1) Equivalent Boe are calculated using an energy equivalent ratio of six Mcf of natural gas to one Bbl of crude oil. Using an energy-equivalent ratio does not factor in price differences and energy-equivalent prices may differ significantly among produced products. (2) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. www.sandridgeenergy.com
- 22. Capital Structure Visibly longliquidity runway on unlevered balance sheet $425MM UNDRAWN BORROWING BASE $417MM available ($8MM LOCs) STRONG LIQUIDITY $36MM BUILDING NOTE $750MM COMMON EQUITY 35.9 MM common shares outstanding at $21 per share • $600MM committed • First redetermination Oct 2017 • March 2020 maturity (1) as of February 23rd ~$120MM CASH1Zero Net Debt 0.0x net leverage 22
- 23. 2017 Capital ExpendituresGuidance 23 CAPEX GUIDANCE DETAIL $MM Mid-Continent D&C $65 - $70 North Park D&C 20 - 25 Other - D&C1 24 Total Drilling & Completion $109 - $119 OTHER E&P Land, G&G and Seismic $40 Infrastructure2 7 Workovers 37 Capitalized G&A and Interest 15 Total Other E&P $99 NON E&P General Corporate 2 Total Capital Expenditures _(excl. A&D and P&A) $210 - $220 CAPEX GUIDANCE $MM D&C $109 - $119 Other E&P 99 Total Exploration and Production $208 - $218 General Corporate 2 Total Capital Expenditures $210 - $220 LATERAL SPUDS GROSS NET Mid-Continent 22 17 North Park 6 6 Total Laterals 28 23 (1) 2016 Carryover, Coring, and Non-Op (2) Facilities - Electrical, SWD, Gathering, Pipeline ROW www.sandridgeenergy.com
- 24. 2017 Operational Guidance 24 TOTALCOMPANY PRODUCTION Oil (MMBbls) 4.0 – 4.2 Natural Gas Liquids (MMBbls) 3.0 – 3.2 Total Liquids (MMBbls) 7.0 – 7.4 Natural Gas (Bcf) 42.0 – 43.5 Total (MMBoe) 14.0 - 14.7 PRICING REALIZATIONS Oil (differential below WTI) $2.75 NGLs (realized % of WTI) 26% Gas (differential below Henry Hub) $1.00 COSTS PER BOE LOE $8.00 - $9.00 Adj. G&A – Cash1 $4.25 - $4.50 % OF NET REVENUE Severance Taxes 2.75% - 3.00% (1) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, and other non-recurring items. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods. www.sandridgeenergy.com
- 25. Hedging Overview 25 OIL Q1’17Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (MMBbls) 0.81 0.82 0.83 0.83 3.29 0.45 0.46 0.46 0.46 1.83 Price ($/Bbl) $52.24 $52.24 $52.24 $52.24 $52.24 $55.34 $55.34 $55.34 $55.34 $55.34 NATURAL GAS Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (Bcf) 8.10 8.19 8.28 8.28 32.85 0.90 0.91 0.92 0.92 3.65 Price ($/Mcf) $3.20 $3.20 $3.20 $3.20 $3.20 $3.12 $3.12 $3.12 $3.12 $3.12 Note: As of 2.22.17 www.sandridgeenergy.com
- 26. Reconciliation of StandardizedMeasure of Discounted Net Cash Flows to PV-10 26 www.sandridgeenergy.com The PV-10 of strip-based proved reserves is a non-GAAP financial measure and differs from standardized measure because it reflects the estimated proved reserves economically recoverable based on forward NYMEX strip prices rather than SEC pricing and does not include the effects of income taxes on future net revenues. Proved Reserves Successor Dec 31, 2016 Predecessor Dec 31, 2015 ((in millions) Standardized measure of discounted net cash flows1 $ 438 $ 1,314 Present value of future net income tax expense discounted at 10% - 1 PV-102 $ 438 $ 1,315 Effects of calculating reserves and pricing using strip pricing 508 PV-10 of strip-based proved reserves $ 946 (1) Includes approximately $225 million attributable to SandRidge noncontrolling interests at December 31, 2015. (2) Includes approximately $226 million attributable to SandRidge noncontrolling interests at December 31, 2015.