Final august investor presentation

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  1. 1. 1 INVESTOR PRESENTATION AUGUST 2017
  2. 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 companys 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 and other costs, operational optimization initiatives, anticipated efficiency improvements and cost reductions, liquidity and capital structure. 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, 2016 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 SECs 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 companys proved reserves, as calculated under current SEC rules, we refer you to the companys amended Annual Report on Form 10-K referenced above, which is available on our website at www.sandridgeenergy.com and at the SECs website at www.sec.gov. 1 Forward Looking Statement www.sandridgeenergy.com
  3. 3. SandRidge Energy With a strong balance sheet, we have built a portfolio of three project areas with competitive project IRRs and significant location inventories. Investment will continue with the development of both our NW STACK and North Park Niobrara oil projects and high- graded harvest of our Mississippian position, with total company oil production turning the corner in late 2017. 2 www.sandridgeenergy.com $563MM of liquidity including $145MM cash1 Moderate level of outspend Protect the balance sheet High-graded harvest Cash flow generation Continued cost reductions Well design innovation 50% of 2017 D&C Capex Expands drilling inventory Dominant acreage position held by production or unit Multiple benches and tighter spacing upsides >80% oil resource 50% of 2017 D&C Capex Meramec & Osage 70k net acres in 3 counties Major, Woodward & Garfield Counties Increased oil exposure (1) Cash balance as of July 31st
  4. 4. Valuation as of August 2, 2017 Market Capitalization $690 Million Debt 38 Less: Available Cash (145) Enterprise Value $583 Million Liquidity Cash $145 Million Undrawn Revolver2 418 Cash + RBL $563 Million Production & Reserves Q217 Production 42.1 MBoepd (27% oil) YE16 Proved Reserves3 180 MMBoe (31% oil) $763MM Strip PV-10 3 SandRidge Energy Overview Unlevered with strong liquidity and portfolio of oil-weighted opportunities (1) Held by production (HBP) or held by unit (2) $425 million borrowing base less $7 million in letters of credit (3) Reserves as of 12.31.16 and PV-10 using actual realized pricing and 3.20.17 Strip pricing (~$50/$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. 390k 79% HBP 125k 57% HBP1 70k 30% HBP Large Acreage Positions in Three Assets Held by Production or Federal Unit
  5. 5. NW STACK $200 million Drilling Participation Agreement with $100 million of initial funding 902 Boepd (81% oil) 30-Day IP on Campbell 2015 1-26H, XRL targeting Meramec in Major County 4 Q217 Operational and Financial Results GUIDANCE UPDATE Successful NW STACK drilling and North Park outperformance build momentum FINANCIAL HIGHLIGHTS North Park Niobrara Improved type curve due to shallower oil decline Resumed drilling in June with one rig targeting multiple zones Extended favorable ~$3.15 differential to WTI through 2018 Results $46 million of adjusted EBITDA with $57 million of capex LOE reductions driven by electrical efficiency initiatives and chemical program improvements $15 million proceeds from non-core asset sales Liquidity & Leverage $563 million total liquidity, including $145 million of cash $418 million available on undrawn revolver ($7 million in letters of credit) 0.0x net leverage Raising full year production guidance by 200 MBoe to 14.2 14.9 MMBoe, with oil comprising 50% of the increase Decreasing LOE by 15% to $7.00 - $7.50 per boe, or $16 million at the midpoint of guidance Capex guidance increasing to $250 - $260 million OPERATING ACTIVITY
  6. 6. 5 NW STACK Asset Overview Meramec and Osage development extending northwest Overlaying Major, Garfield, Woodward, Blaine and Dewey counties Approximately 100 miles east to west Meramec and Osage formations Same productive formations as STACK Structurally deepens from northeast to southwest Over-pressured reservoir extends into NW STACK High oil content
  7. 7. 6 NW STACK Primary Targets Meramec 5,800-12,400 TVD Interbedded shales, sands, and carbonates Thickness from 50-160 Matrix porosity development in limey-sand zones with some secondary fracturing Osage 5,900-12,500 TVD Limestone and cherts Thickness from 450-1,300 Natural fracturing enhances productivity
  8. 8. 7 NW STACK SD History SandRidge has operated in the NW STACK for many years NW STACK activity began on the southern acreage of Miss Lime asset Drilled Osage wells in 2014-2015 Meramec targeting commenced in 2016 Expanded acreage position through organic leasing and 13k acreage acquisition in early 2017 Signed Drilling Participation Agreement in July 2017 SD Initial Meramec/Osage Wells
  9. 9. 8 NW STACK Drilling Participation Agreement Transaction highlights NW STACK asset value Drilling Agreement Terms $200MM agreement with $100MM initial funding to drill within 30 dedicated sections Wellbore-only conveyance, targeting the Meramec Carry and reversionary interest structure SandRidge retains all operational control Key Highlights and Benefits to SandRidge Accelerated delineation increases net asset value Reduced capital expenditure requirements with carried working interest structure 12 additional laterals in 2017 (to 34 from 22) while reducing D&C $5MM Realizes higher rate of return with carry and reversionary working interest structure Drilling Program Primarily Within Major and Woodward Counties
  10. 10. 9 NW STACK Activity Delineating NW STACK alongside other operators 20 Rigs from 12 Operators SandRidge Activity 2017 D&C capex of $60-65MM 34 laterals planned for 2017 Targeting $3.3MM D&C per lateral Drilling Meramec formation Retaining Osage as upside Optimizing completion designs Coring and 3D seismic enhance reservoir characterization
  11. 11. 10 Industry Meramec Results Meramec production has averaged 700-800 Boepd and ~60% oil on wells surrounding SDs NW STACK acreage position
  12. 12. 11 Industry Osage Results Osage production has averaged 700-800 Boepd and ~40% oil on wells surrounding SDs NW STACK acreage position
  13. 13. 12 Dominant position of 125k net acres Stacked Niobrara pay with multiple benches 57% held by production or federal unit 30 MMBoe (87% oil) of P1 Reserves1 1,300 2P locations Q217 production of 172 MBo (1.9 MBopd) 10 wells drilled in 2016, including one XRL North Park Niobrara Asset Overview Large contiguous acreage position in Jackson County, Colorado Repeatable resource play expands drillable inventory and enhances oil value (1) SEC Reserves as of 12.31.16
  14. 14. 13 North Park Niobrara Analogous to Wattenberg North Parks gross Niobrara interval ranges from 460 - 500 feet thick
  15. 15. 14 Targeting Multiple Niobrara Benches Stacked pay potential with proven production from multiple benches Proved production from C and D benches Drilling B bench this year Initial production ranging 400-550 Boepd (90% oil) per 1-mile lateral C bench target is strongest SRL to date Proceeded 2017 drilling with more cost efficient XRLs 600 MBoe EUR (513 MBo or 85% oil)
  16. 16. RABBIT EARS UNIT 24k Net Acres SURPRISE UNIT 22k Net Acres PETERSON RIDGE UNIT 22k Net Acres 15 North Park Geology Update Increased subsurface understanding with additional seismic and core analysis Integrating 3D seismic for well placement and targeting 117 square miles of seismic from three surveys including 61 square miles of 3D seismic obtained this year Core collection and analysis will aide in stimulation, well spacing and reservoir characterization Over 500 feet of core being collected in 2017 Previous core of 300 feet collected in 2007
  17. 17. 16 North Park Niobrara Uniform Thickness Consistent thickness across entire acreage position
  18. 18. 17 2017 D&C capex of $60-65MM Resumed drilling in June with one rig 11 XRLs planned for 2017 Three XRLs will hold 37k net acres in three federal units Drilling XRLs exclusively Targeting $3.6MM D&C per lateral Drilling increases acreage held by production or by unit to ~85% by year-end 2017 Processing and interpreting new 3D seismic survey Analyzing a full core recently cut through Niobrara Production outperformance drives improved type curve North Park Niobrara Activity Increasing activity as a result of production outperformance and federal unit approval Net Acreage Held by Federal Unit
  19. 19. 18 2016 Niobrara Program Success 2016 Drilling Results Note: 30-Day IP rates shown above 10 wells drilled in 2016, outperforming type curve Lowered costs, optimized completions, drilled first XRL and C bench wells
  20. 20. 19 Optimized completions from 2016 drilling program Niobrara Oil Production DAILY OIL RATE CUMULATIVE OIL
  21. 21. 20 Niobrara Type Curve Update Jet Pump Installed Shallower decline vs initial estimates drive value improvement Type Curve Cumulative Oil Production (MBo) Initial Current 90 Days 66 66 180 Days 103 113 365 Days 139 164 50 Years 513 513 XRL TYPE CURVE UPLIFT IMPROVED ECONOMICS PV-10 increase of ~$1MM IRR uplift
  22. 22. 21 North Park Basin Oil and Gas Takeaway Favorable oil marketing and gas processing will create additional revenue Current Marketing andTakeaway Short term in-field gas processing options include: Mechanical Refrigeration Units (MRU) for NGL extraction first contract executed Gas-to-liquids (GTL) Gas injection currently drilling test well Potential to generate additional revenue, reduce emissions and augment longer term pipeline plans Oil trucked to market (up to 40 MBopd) Extended favorable ~$3.15 differential to WTI through 2018 Gas combusted under appropriate permits Building out field gathering infrastructure; centralized tank battery used for processing, storage and export
  23. 23. APPENDIX 22
  24. 24. 23 First SandRidge Niobrara C Bench Lateral Hebron 4-18H, strongest well to date, outperforming type curve DAILY OIL RATE CUMULATIVE OIL Jet Pump Installed
  25. 25. 24 First SandRidge Niobrara XRL Castle 1-17H, in line with current type curve DAILY OIL RATE CUMULATIVE OIL Jet Pump Installed Jet Pump Installed
  26. 26. 25 2017 Project EURs, Economics & Inventory EURs & ECONOMICS MERAMEC NIOBRARA MISSISSIPPIAN XRL* SINGLE XRL FSD* SINGLE EUR, MBoe % Oil 800 1,000 40%+ 500 600 40%+ 600 80%+ 1,350 20% 550 20% D&C per lateral ($MM) $3.3 $4.3 $3.6 $2.0 $2.4 IRR(a) 16 - 28% 14 - 23% 32% 49% 14% PV-10(a) ($MM) $1.2 - $3.3 $0.5 - $1.5 $3.3 $4.4 $0.3 YE16 INVENTORY NW STACK NIOBRARA MISSISSIPPIAN PUDs (laterals) 6 106 51(b) Probables (laterals) Under evaluation (4-8 per section) ~1,180 ~180(b) Net acres 70k 125k 390k HBP or HBU 30% 57% 79% a) @ July 28th Strip avg pricing (~$50 /~$3.00) at 100% Working Interest b) Excluding ~70 Proven + Probable Chester locations Diverse and material location inventory in three areas *FSD = Full Section Development, equivalent to 3 laterals *XRL = Extended Reach Lateral, 2-mile lateral
  27. 27. Year End 2016 Reserves and PV-10 26 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 (~$50 / ~$3) 55,686 37,687 521,173 180,235 $763_ (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
  28. 28. Four Quarters of Trailing Actuals 27 ACTUALS PRODUCTION Q316 Q416 Q117 Q217 Oil (MMBbls) 1.3 1.2 1.1 1.0 Natural Gas Liquids (MMBbls) 1.1 1.0 0.9 0.9 Total Liquids (MMBbls) 2.4 2.2 2.0 1.9 Natural Gas (Bcf) 13.1 12.8 11.8 11.3 Total (MMBoe) 4.6 4.3 4.0 3.8 Daily Oil Equivalent (MBoepd) 49.6 47.2 44.2 42.1 PRICING REALIZATIONS Oil (differential below WTI) $2.11 $2.28 $2.71 $2.26 NGLs (realized % of WTI) 31% 30% 32% 29% Gas (differential below Henry Hub)1 $0.54 $0.93 $0.96 $1.11 COSTS PER BOE LOE1 $8.68 $5.76 $6.28 $6.59 Adj. G&A Cash2 $3.88 $3.08 $3.43 $3.70 % OF NET REVENUE Severance Taxes 2.3% 2.7% 3.2% 3.1% (1) Q416 marks beginning of accounting policy change to book gas transportation fee as a net from revenue, rather than a lease operating expense (2) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, and other non-recurring items. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods. www.sandridgeenergy.com
  29. 29. Updated 2017 Guidance 28 CAPEX GUIDANCE ($MM) UPDATED PREVIOUS D&C $140 - $150 $109 - $119 Other E&P 108 99 Total Exploration and Production $248 - $258 $208 - $218 General Corporate 2 2 Total Capital Expenditures $250 - $260 $210 - $220 TOTAL COMPANY PRODUCTION Oil (MMBbls) 4.1 4.3 4.0 4.2 Natural Gas Liquids (MMBbls) 3.1 3.3 3.0 3.2 Total Liquids (MMBbls) 7.2 7.6 7.0 7.4 Natural Gas (Bcf) 42.0 43.5 42.0 43.5 Total (MMBoe) 14.2 - 14.9 14.0 - 14.7 www.sandridgeenergy.com PRICING REALIZATIONS UPDATED PREVIOUS Oil (differential below WTI) $2.75 $2.75 NGLs (realized % of WTI) 28% 26% Gas (differential below Henry Hub) $1.00 $1.00 COSTS PER BOE LOE $7.00 - $7.50 $8.00 - $9.00 Adj. G&A Cash1 $4.25 - $4.50 $4.25 - $4.50 % OF NET REVENUE Severance Taxes 3.00% - 3.25% 2.75% - 3.00% (1) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, and other non-recurring items. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods.
  30. 30. 2017 Capital Expenditures Detail 29 CAPEX GUIDANCE ($MM) UPDATED PREVIOUS Mid-Continent D&C $60 - $65 $65 - $70 North Park D&C 60 - 65 20 - 25 Other - D&C1 20 24 Total Drilling & Completion $140 - $150 $109 - $119 OTHER E&P Land, G&G and Seismic $46 $40 Infrastructure2 18 7 Workovers 30 37 Capitalized G&A and Interest 14 15 Total Other E&P $108 $99 NON E&P General Corporate 2 2 Total Capital Expenditures (excl. A&D and P&A) $250 - $260 $210 - $220 GROSS LATERAL SPUDS UPDATED PREVIOUS Mid-Continent3 34 22 North Park 22 6 Total Laterals 56 28 NET LATERAL SPUDS Mid-Continent3 17 17 North Park 22 6 Total Laterals 39 23 (1) 2016 Carryover, Coring, Non-Op and SWD (2) Infrastructure: Production Facilities, Pipeline ROW and Electrical (3) Updated lateral count includes 12 Drilling Participation Agreement laterals www.sandridgeenergy.com
  31. 31. 30 Hedging Overview 78% of oil and 77% of gas volumes hedged at the midpoint of guidance in 2017 OIL Q117 Q217 Q317 Q417 FY 2017 Q118 Q218 Q318 Q418 FY 2018 SWAPS Total Volumes (MMBbls) 0.81 0.82 0.83 0.83 3.29 0.45 0.46 0.46 0.46 1.83 Daily Volumes (MBblspd) 9.0 9.0 9.0 9.0 9.0 5.0 5.0 5.0 5.0 5.0 Price ($/Bbl) $52.24 $52.24 $52.24 $52.24 $52.24 $55.34 $55.34 $55.34 $55.34 $55.34 NATURAL GAS Q117 Q217 Q317 Q417 FY 2017 Q118 Q218 Q318 Q418 FY 2018 SWAPS Total Volumes (Bcf) 8.10 8.19 8.28 8.28 32.85 5.40 3.64 3.68 3.68 16.40 Daily Volumes (MMBtupd) 90.0 90.0 90.0 90.0 90.0 60.0 40.0 40.0 40.0 44.9 Price ($/MMBtu) $3.20 $3.20 $3.20 $3.20 $3.20 $3.23 $3.11 $3.11 $3.11 $3.15 Note: As of 7.30.17
  32. 32. Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10 31 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 325 PV-10 of strip-based proved reserves $ 763 (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.