INVESTOR PRESENTATION
NOVEMBER 2016
INVESTOR PRESENTATION CAUTIONARY STATEMENTS Forward Looking - - PowerPoint PPT Presentation
NOVEMBER 2016 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
NOVEMBER 2016
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
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
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.
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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.
3 www.sandridgeenergy.com
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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
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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 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
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(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
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MULTI AND EXTENDED LATERALS 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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– +/- 300’ thick carbonate at ~6,000’ TVD
– 1,095 miles of pipeline, connected to 136 active disposal wells, injecting ~660 MBwpd
– 1,250 miles of power lines, six substations and two micro grids
DIVERSE ASSET WITH FOCUS EXPANDING BEYOND MISSISSIPPIAN INTERVAL IN OKLAHOMA
with 36% IRR1, all multi or extended laterals
per lateral of $1.9MM
(equivalent to 4 single laterals)
(equivalent to 3 single laterals)
(equivalent to 2 single laterals)
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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
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for 600 MBoe EUR
production; three laterals in early evaluation phase and three brought
~75k net acres currently held by production or unit (56%)
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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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
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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 OF 75 MBO AT 217 DAYS
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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
wells during November and December
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LAST 14 LATERALS USING MODERN COMPLETION DESIGNS
14 LATERALS SUPPORTING TYPE CURVE CUMULATIVE OIL
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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
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LOWER COSTS, OPTIMIZED COMPLETIONS, EXTENDED LATERALS, 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
beyond existing 54 square miles of 3D seismic by acquiring additional 64 square miles of 3D seismic starting in 2017
recovery, while reducing costs
and observing DJ Basin operators
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WTI OIL DIFFERENTIAL REDUCED FROM $11+/BBL TO $3.15/BBL
NORTH PARK BASIN POTENTIAL PIPELINE ROUTES
CURRENT OIL AND GAS DISPOSITION
battery concept used for processing, storage and export
handle 40 MBopd)
MIDSTREAM STRATEGY
with Mechanical Refrigeration Units (MRUs)
volumes
– Currently proceeding with engineering, permitting and right-of-way acquisition for oil and natural gas pipelines
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– ~1,300 producing horizontal wells, 3D seismic and improved reservoir characterization – One rig active most of 2016 – Production decline moderating – Infrastructure in place
– Drilling and completing with encouraging results – 1,300 proved and probable locations and significant PUD potential
– ~$111MM of unrestricted cash – Undrawn $425MM revolver2
(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
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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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$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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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)