INVESTOR PRESENTATION
JANUARY 2017
INVESTOR PRESENTATION CAUTIONARY STATEMENTS Forward Looking - - PowerPoint PPT Presentation
JANUARY 2017 INVESTOR PRESENTATION CAUTIONARY STATEMENTS Forward Looking Statement This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of
JANUARY 2017
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
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
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.
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Forward Looking Statement
www.sandridgeenergy.com
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.
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Outspend
(Meramec/Osage)
Costs
Results
Position
Inventory
(“XRL”) & Multilaterals (“Multi”)
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UNLEVERED OIL PRODUCER FOCUSED ON RESOURCE VALUE CREATION
KEY INFORMATION
FULLY DILUTED MARKET EQUITY VALUE @ $24 / SHARE 20.6 MM Common shares + 14.8 MM Conversion shares = Estimated Market Cap $494 Million + $ 355 Million = $850 Million PRIMARY ASSETS
Mid-Continent Focus Area 458k
Net Acres
~300 2P
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Locations
(includes prospective Meramec/Osage) (excludes prospective Meramec/Osage)
North Park Basin Niobrara Oil 133k
Net Acres
~1,300 2P
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Locations
PRODUCTION & RESERVES
Q3’16 Production 49.6 MBoepd
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(28% oil)
SEC Proved Reserves 281 MMBoe at YE’15
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(25% oil)
138 MMBoe at Q3’16
~20% higher at recent strip pricing (1) 2P locations: Undeveloped Proved and Probable (2) Excludes production related to noncontrolling interests (3) 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)
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supporting competitive IRRs at Dec 2016 strip
– Production decline moderating as 2014-15 producers mature
– ~$536MM liquidity, ~$111MM of unrestricted cash, & undrawn $425MM revolver2
(1) Excluding mandatorily convertible notes (2) Pro Forma for debt pay down following emergence on 10.4.16 and excludes approximately $10MM of LOCs
HARVEST & APPRAISE
MID-CONTINENT HIGH-GRADE PLUS ADJACENT MERAMEC/OSAGE DRILLING IN THREE COUNTIES
DIVERSIFY
GROW OIL RATE AND RESERVES IN NIOBRARA
UN-LEVERED
STRONG FINANCIAL POSITION
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PLUS 2017 PUD ADDITIONS IN BOTH MID-CONTINENT AND NIOBRARA
– Late 2016 Miss XRLs (4 laterals total) at <$1.5MM D&C per lateral – Drilling technology and well cost reduction focus transfer to both Meramec /Osage and Niobrara
– Major, Garfield, and Woodward Counties – Potential for material PUD additions in 2017
– Sub-$3MM D&C per lateral targeted in 2017 program (100% XRLs) – Potential for material PUD additions in 2017
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2017 MERAMEC/OSAGE PROGRAM IN 3 OKLAHOMA COUNTIES
POTENTIAL TO ADD MATERIAL LOCATIONS THROUGH MERAMEC/OSAGE DEVELOPMENT
Osage wells producing in Garfield to be followed up by 1 Meramec XRL in 2017
Meramec and Osage production, to be followed up by 4 Meramec XRLs in 2017
2017 with 1 XRL adjacent to peer production
2017 activity supports appraisal of three counties
INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE INDUSTRY ACTIVITY IS CONVERGING ON EXISTING SANDRIDGE ACREAGE SD Meramec/Osage activity in 3 counties:
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– Mississippian – Chester/Manning – Meramec/Osage gaining industry attention
– +/- 300’ thick carbonate at ~6,000’ TVD – Over 1,600 horizontal wells drilled in OK & KS since 2010
– 1,095 miles of pipeline, connected to 136 active disposal wells
– 1,250 miles of power lines, six substations and two micro grids
458K NET ACRES IN OKLAHOMA, WITH MISSISSIPPIAN, CHESTER, AND MERAMEC/OSAGE PRODUCTION
KS OK
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MULTIS AND XRLS ARE A BREAKTHROUGH IN MISSISSIPPIAN
D&C CAPEX, $MM PER LATERAL
Lower costs per lateral
90-DAY CUMULATIVE MBOE PER LATERAL
Results shown by groups of 50 wells
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HIGH-GRADE YIELDING TIGHTER EUR DISTRIBUTIONS WITH BETTER RESERVOIR CHARACTERIZATION
more consistent results
locations form reliable inventory
support competitive returns
P10 / P90 RATIO
2013 2014 2015 2016 7 8 7 2
PROJECTED EURS
NORMALIZED BY LATERAL
$1.7MM Avg D&C per Lateral
(equivalent to 4 single laterals)
(equivalent to 4 single laterals)
(equivalent to 3 single laterals)
(equivalent to 2 single laterals)
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MULTIS AND XRLS REDUCE COSTS AND PRESERVE COMPETITIVE RETURNS AT LOWER COMMODITY PRICES
(1) Estimated based on historical realized pricing + 12.19.16 NYMEX Strip and actual production + forecasted production
2016: 13 Miss laterals 51% IRR
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100% Multi and XRL
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with projected 600 MBoe EUR and targeting sub- $3MM per lateral in 2017
drilling requirements, ~75k net acres currently held by production or unit (56%)
unit by year end 2017, for a total of ~108k net acres held by unit or production (81%)
DOMINANT ACREAGE POSITION WITH HIGH OIL CUT
(1) SandRidge reserves as of 12.31.15, based on SEC pricing ($46.79 / $2.59)
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REDUCING COSTS $500K PER LATERAL SUPPORTS LARGE IRR UPSIDE; CURRENT COSTS ACHIEVED AFTER JUST 11 LATERALS INCLUDING ONLY 1 XRL
Assumptions: XRL $7.0MM D&C cost ($3.5MM per lateral), 600 MBoe EUR
XRL
CURRENTLY $3.5MM PER LATERAL Targeting <$3.0MM per lateral Current $3.5MM per lateral
Reducing cost per lateral of XRLs will be a priority in 2017
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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%
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478 BOEPD (90% OIL) AVERAGE 30-DAY IP ON FIRST FIVE SANDRIDGE LATERALS
DESIGNED TO TEST
SIX LATERALS ONLINE IN LATE 2016 FIRST FIVE SANDRIDGE LATERALS Initial results of 2H’16 wells to be released with Q4’16 earnings
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GREGORY 1-9H, 550 BOEPD (89% OIL) 30-DAY IP
THE GREGORY 1-9H CONTINUES TO OUTPERFORM TYPE CURVE
Cumulative production
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AVERAGE OIL RATE OF FIRST FIVE SANDRIDGE LATERALS DRILLED
FIRST 5 SANDRIDGE LATERALS
artificial lift
accelerating artificial lift on future installations
remaining 2016 laterals in Q1’17
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LAST 14 LATERALS USING MODERN COMPLETION DESIGNS
14 LATERALS SUPPORTING TYPE CURVE CUMULATIVE OIL
Average Cumulative Oil 126,298 Bbls 96,917 Bbls Cumulative Type Curve Oil
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LOWER COSTS, OPTIMIZED COMPLETIONS, XRLS, STACKED PAY AND LOCATION COUNT
HBP AND FEDERAL UNITS HOLD 56% OF ACREAGE
UPSIDE INCLUDES
completed in Q3’16 and brought online in Q4’16
– 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
characterization model beyond existing 54 square miles of 3D seismic by acquiring additional 64 square miles of 3D seismic starting in 2017
ultimate recovery, while reducing costs
learnings and observing DJ Basin operators
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WTI OIL DIFFERENTIAL HAS BEEN REDUCED FROM $11+/BBL TO $3.15/BBL
NORTH PARK BASIN POTENTIAL PIPELINE ROUTES
CURRENT OIL AND GAS DISPOSITION
tank battery used for processing, storage and export
could handle 40 MBopd)
MIDSTREAM STRATEGIC OPTIONS
stream with gas reinjection being considered to reduce combustion volumes
– Currently proceeding with engineering, permitting and right-of-way acquisition for oil and natural gas pipelines
Plains Rocky Mountain Pipeline Rockies Express Pipeline (REX) Colorado Interstate Gas Pipeline (CIG)
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COMMON EQUITY MANDATORILY CONVERTIBLE DEBT $425MM REVOLVING CREDIT FACILITY $111MM CASH
$536MM Liquidity
(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 on 10.4.16 and excludes approximately $10MM of LOCs Note: In addition to the items above there is a $35MM note secured by the Company’s non-oil and gas real property
net share settled
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$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)
8.75% Senior Unsecured Notes due 2020 $ 396 $ (396) $ - 7.50% Senior Unsecured Notes due 2021 758 (758)
528 (528)
544 (544)
$ 2,225 $ (2,225) $
8.125% Senior Unsecured Convertible Notes due 2022 $ 41 $ (41) $
47 (47)
$ 3,641 $ (3,606) $ 35 0.00% Mandatorily Convertible Senior Subordinated Notes2
278 Total Debt $ 3,641 $ (3,328) $ 313
Liquidity
RBL Borrowing Base3 $ 500 $ (75) $ 425 RBL Available
425 Cash 634 (523) 111 Total Liquidity $ 634 $ (98) $ 536
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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.
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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 - $240
LATERAL SPUDS GROSS NET
Mid-Continent 26 21 North Park 11 11 Total Laterals 37 32
(1) 2015 Carryover, JV Penalty, Rig Penalty, Non-Op, SWD (2) Facilities - Electrical, SWD, Gathering, Pipelines
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OIL
Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (MMBbls) 1.29 0.63 0.64 0.64 0.64 2.56 0.27 0.27 0.28 0.28 1.10 Price ($/Bbl) $56.45 $51.45 $51.45 $51.45 $51.45 $51.45 $55.10 $55.10 $55.10 $55.10 $55.10
NATURAL GAS
Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 SWAPS Volumes (Bcf) 10.92 7.20 7.28 7.36 7.36 29.20 Price ($/Mcf) $2.86 $3.19 $3.19 $3.19 $3.19 $3.19 BASIS SWAPS (PEPL) Volumes (Bcf) 0.92 NA NA NA NA NA Price ($/Mcf) ($0.38) NA NA NA NA NA
Note: As of 11.08.16