INVESTOR PRESENTATION
MAY 2017
PRESENTATION Cautionary Statements Forward Looking Statement This - - PowerPoint PPT Presentation
MAY 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 the
MAY 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 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 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 built a portfolio of three project areas with competitive project IRRs and significant location
graded harvest of our Mississippian position, with total company oil production turning the corner in late 2017.
2 www.sandridgeenergy.com
including ~$137MM cash1
tighter spacing upsides
‐ Major, Woodward & Garfield Counties
(1) Cash balance as of May 4th
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Unlevered oil producer focused on resource value creation
KEY INFORMATION
Market Equity Value as of May 9, 2017
35.9 MM common shares $656 Million
Primary Assets
2P Locations1 Net Acres
Mississippian
Anadarko Basin, OK
~300 400k
NW STACK
Anadarko Basin, OK
Under Evaluation 70k
Niobrara Shale
North Park Basin, CO
~1,300 127k
Production & Reserves
Q1’17
Production
44.2 MBoepd (28% oil)
YE’16
Proved Reserves2
180 MMBoe (31% oil) $763MM Strip PV-10
(1) 2P locations: Undeveloped Proved and Probable (2) 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.
NW STACK Meramec/Osage Delineation
Woodward, Co. (previously disclosed)
total to 70k net acres
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STRONG PERFORMANCE
Generated $15 million free cash flow in Q1’17
Mississippi Lime Cash Flow Generation
(Full section development)
ADVANTAGED BALANCE SHEET
Strong liquidity and no net debt
North Park Niobrara Targeting Multiple Benches
(61 sq. mi.)
(1) Excludes $48 million NW STACK acquisition (Woodward Co.) announced on Feb 22nd (2) @ April 26th Strip pricing (~$50 /~$3.00)
Continued NW STACK drilling, Niobrara production outperformance and Miss Lime success
THREE PROJECT PORTFOLIO
Two rigs in NW STACK One rig resuming at North Park at midyear Miss Lime generating cash flow
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SD currently running 2 rigs across 70k acres in NW STACK (Major, Woodward and Garfield Co.)
Meramec and Osage results
producing in Woodward
INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE
Industry activity has been converging
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NW STACK Meramec and Osage same productive formation as in STACK Structurally deepens from northeast to southwest
Meramec 5,800’-12,400’ TVD
carbonates
zones with some secondary fracturing
Lower Osage 5,900’-12,500’ TVD
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2 Rigs currently running across three counties
2017 D&C capex of $65-70MM
Currently flowing back
Currently completing
Currently drilling
70K NET ACRES IN NW STACK
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Meramec initial production has averaged 700-800 Boepd and ~60% oil on wells surrounding SD’s NW STACK acreage position
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Osage initial production has averaged 700-800 Boepd and ~40% oil on wells surrounding SD’s NW STACK acreage position
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projected 600 MBoe total EUR
Federal Unit
acquire a full core across the Niobrara
Drilling in 2017 focuses on XRLs, multiple benches and establishes new federal unit
2017 activity will help optimize full development planning
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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%
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11 laterals drilled in 2016, outperforming type curve Lowered costs, optimized completions, drilled first XRL and “C” bench wells
First st XRL in the basin sin
completed for $3.4MM per lateral with a 30-Day IP of
First “C” bench well
second highest per lateral 30-Day IP of 539 Boepd (92% oil)
Adv Advanced d drill illin ing and com
letion tion des esigns igns
cross-linked gel (vs slickwater) fracs
2016 DRILLING RESULTS
Note: 30-Day IP rates shown above
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Hebron 4-18H cumulative oil production exceeds type curve by 32% 539 Boepd (92% oil) 30-Day IP
DAILY OIL RATE CUMULATIVE OIL
Jet Pump Installed
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901 Boepd (91% oil) 30-Day IP
Castle 1-17H exceeding type curve, drilled and completed for $3.4MM per lateral
DAILY OIL RATE CUMULATIVE OIL
Jet Pump Installed Jet Pump Installed
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Current year program to feature XRLs with crosslinked completions
2016 DRILLING PROGRAM
2016 CROSSLINKED COMPLETIONS ONLY
RABBIT EARS UNIT 24k Net Acres SURPRISE UNIT 22k Net Acres PETERSON RIDGE UNIT 22k Net Acres
BEAVER CREEK UNIT 11k Net Acres (Proposed)
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– Planned XRL to be drilled in Rabbit Ears Unit will hold the 24k net acres
2017 drilling increases acreage held by production or by unit to ~75% of existing 127k net acre position
71k net acres currently held by production or unit (56% of 127k net acre position). Three existing and one proposed Federal Unit:
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Favorable oil marketing and gas processing will create additional revenue
Curren ent Marketin ting and Takeaway Shor
t term m in-fie ield ld gas proc
ssing ing may includ lude: :
extraction
emissions and augment longer term pipeline plans
tank battery used for processing, storage and export
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EURs & ECONOMICS MERAMEC NIOBRARA MISSISSIPPIAN
XRL* SINGLE XRL FSD* SINGLE EUR, MBoe
% Oil
800 – 1,000
40%+
500 – 600
40%+
600
80%+
1,350
20%
550
20%
D&C per lateral ($MM) $3.1 $4.2 $3.4 $2.0 $2.4 IRR(a) 20 - 35% 15 - 25% 27% 52% 14% PV-10(a) ($MM) $1.8 - $3.9 $0.6 - $1.6 $2.9 $4.7 $0.4
YE’16 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 127k 400k HBP or HBU 33% 56% 78%
a) @ Apr 26th 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
1 dual XRL: : (equivalent to 4 single laterals)
ion develop velopmen ent: : (equivalent to 3 single laterals)
lanar: ar: (equivalent to 2 single laterals)
(equivalent to 4 single laterals)
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$1.7MM Avg D&C per Lateral, 100% Multi and XRL
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Multis and XRLs drive lower costs with consistent results
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
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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) (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.
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ACTUALS PRODUCTION Q2’16 Q3’16 Q4’16 Q1’17 Oil (MMBbls) 1.4 1.3 1.2 1.1 Natural Gas Liquids (MMBbls) 1.1 1.1 1.0 0.9 Total Liquids (MMBbls) 2.5 2.4 2.2 2.0 Natural Gas (Bcf) 14.5 13.1 12.8 11.8 Total (MMBoe) 5.0 4.6 4.3 4.0 Daily Oil Equivalent (MBoepd) 54.7 49.6 47.2 44.2 PRICING REALIZATIONS
Oil (differential below WTI)
$3.86 $2.11 $2.28 $2.71
NGLs (realized % of WTI)
29% 31% 30% 32%
Gas (differential below Henry Hub)1
$0.47 $0.54 $0.93 $0.96 COSTS PER BOE
LOE1
$8.58 $8.68 $5.76 $6.28
$2.88 $3.88 $3.08 $3.43 % OF NET REVENUE
Severance Taxes
2.2% 2.3% 2.7% 3.2%
(1) Q4’16 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.
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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
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TOTAL COMPANY 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
$4.25 - $4.50
% OF NET REVENUE
Severance Taxes 2.75% - 3.00%
(1) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, and other non-recurring items. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods.
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80% of oil and 77% of gas volumes hedged at the midpoint of guidance in 2017
OIL
Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (MMBbls) 0.81 0.82 0.83 0.83 3.29 0.45 0.46 0.46 0.46 1.83 Price ($/Bbl) $52.24 $52.24 $52.24 $52.24 $52.24 $55.34 $55.34 $55.34 $55.34 $55.34
NATURAL GAS
Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (Bcf) 8.10 8.19 8.28 8.28 32.85 4.50 2.73 2.76 2.76 12.75 Price ($/MMBtu) $3.20 $3.20 $3.20 $3.20 $3.20 $3.25 $3.11 $3.11 $3.11 $3.16
Note: As of 5.10.17
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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%
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.