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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


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SLIDE 1

INVESTOR PRESENTATION

MAY 2017

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SLIDE 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 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.

1

Forward Looking Statement

www.sandridgeenergy.com

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SLIDE 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

  • $554MM of liquidity

including ~$137MM cash1

  • Moderate level of outspend
  • Protect the balance sheet
  • High-graded harvest
  • Cash flow generation
  • 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
  • 70k net acres in 3 counties

‐ Major, Woodward & Garfield Counties

  • Increased oil exposure

(1) Cash balance as of May 4th

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SLIDE 4

3

SandRidge Energy Overview

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.

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SLIDE 5

NW STACK Meramec/Osage Delineation

  • 13k net acres acquired in

Woodward, Co. (previously disclosed)

  • 10k additional acres, bringing

total to 70k net acres

  • 2nd rig running mid-March
  • 1st Meramec XRL flowing back
  • Licensed 3D seismic survey (329 sq. mi.)

4

Q1’17 Operational and Financial Results

  • 4.0 MMBoe (44.2 MBoepd) production (28% oil)
  • $56 million of adjusted EBITDA with $41 million of capex1
  • $6.28/boe LOE, $10.51/boe total adjusted cash expenses (LOE + severance tax and adjusted cash G&A)
  • No change to guidance
  • $554 million total liquidity
  • $137 million of cash as of May 4th
  • $417 million available on undrawn revolver ($8 million in letters of credit)
  • 0.0x net leverage

STRONG PERFORMANCE

Generated $15 million free cash flow in Q1’17

Mississippi Lime Cash Flow Generation

  • Hawk Haven 2710 1-22H

(Full section development)

  • 1,248 Boepd (47% oil) 30-Day IP
  • $1.8 million D&C per lateral
  • 61% IRR at strip2

ADVANTAGED BALANCE SHEET

Strong liquidity and no net debt

North Park Niobrara Targeting Multiple Benches

  • Drilling to resume at midyear
  • 2016 program exceeding type curve
  • Completed 3D seismic survey

(61 sq. mi.)

  • 24k net acre federal unit approved

(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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SLIDE 6

5

NW STACK Industry Activity

SD currently running 2 rigs across 70k acres in NW STACK (Major, Woodward and Garfield Co.)

  • Multiple operators with NW STACK

Meramec and Osage results

  • 20 rigs currently running
  • Over 100 Meramec and Osage wells

producing in Woodward

INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE

Industry activity has been converging

  • n existing SD acreage with prominent
  • perators seeing encouraging results:
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SLIDE 7

6

NW STACK Primary Targets

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
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SLIDE 8

7

SandRidge NW STACK Delineation

2 Rigs currently running across three counties

2017 D&C capex of $65-70MM

  • 22 gross laterals (17 net laterals)
  • Major, Woodward, and Garfield Co.
  • Targeting the Meramec
  • Drilling mostly XRLs

Currently flowing back

  • Adams 2122 1-16H 9H (Woodward Co. XRL)

Currently completing

  • Campbell 2015 1-26H 23H (Major Co. XRL)

Currently drilling

  • Jack Samuel 2012 1-20H 29H (Major Co. XRL)
  • Landrum 2305 1-30 31H (Garfield Co. XRL)

70K NET ACRES IN NW STACK

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SLIDE 9

8

Industry Meramec Results

Meramec initial production has averaged 700-800 Boepd and ~60% oil on wells surrounding SD’s NW STACK acreage position

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SLIDE 10

9

Industry Osage Results

Osage initial production has averaged 700-800 Boepd and ~40% oil on wells surrounding SD’s NW STACK acreage position

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SLIDE 11

10

  • Ten wells drilled in 2016 including one XRL and
  • ne “C” bench producer with production
  • utperforming type curve
  • Targeting sub-$3.5MM per lateral in 2017 with

projected 600 MBoe total EUR

  • Drill Niobrara “B”, “C” & “D” bench XRLs
  • Drill an XRL to hold 24k net acre Rabbit Ears

Federal Unit

  • Process and interpret new 3D seismic survey;

acquire a full core across the Niobrara

North Park Niobrara Asset Overview

Drilling in 2017 focuses on XRLs, multiple benches and establishes new federal unit

  • 1,300 2P Locations
  • 127k Net acres

2017 activity will help optimize full development planning

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SLIDE 12

11

Targeting Multiple Niobrara Benches

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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SLIDE 13

12

2016 Niobrara Program Success

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

  • 2-mile lateral (Castle 1-17H 20) drilled and completed

completed for $3.4MM per lateral with a 30-Day IP of

  • f 901 Boepd (91% oil)

First “C” bench well

  • Niobrara “C” bench test (Hebron 4-18H) resulted in

second highest per lateral 30-Day IP of 539 Boepd (92% oil)

Adv Advanced d drill illin ing and com

  • mple

letion tion des esigns igns

  • Reduced cycle times, confirmed preference for cross-

cross-linked gel (vs slickwater) fracs

2016 DRILLING RESULTS

Note: 30-Day IP rates shown above

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SLIDE 14

13

First SandRidge Niobrara C Bench Lateral

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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SLIDE 15

14

901 Boepd (91% oil) 30-Day IP

First SandRidge Niobrara XRL

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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SLIDE 16

15

Current year program to feature XRLs with crosslinked completions

2016 DRILLING PROGRAM

2016 Niobrara Oil Production Above Type Curve

2016 CROSSLINKED COMPLETIONS ONLY

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SLIDE 17

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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  • Peterson Ridge Unit: 22k net acres
  • Surprise Unit: 22k net acres
  • Rabbit Ears Unit: 24k net acres

– Planned XRL to be drilled in Rabbit Ears Unit will hold the 24k net acres

  • (Proposed) Beaver Creek Unit: 11k net acres

Large Contiguous North Park Acreage Position

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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SLIDE 18

17

North Park Basin Oil and Gas Takeaway

Favorable oil marketing and gas processing will create additional revenue

Curren ent Marketin ting and Takeaway Shor

  • rt

t term m in-fie ield ld gas proc

  • cess

ssing ing may includ lude: :

  • Mechanical Refrigeration Units (MRU) for NGL

extraction

  • Gas-to-liquids (GTL)
  • Gas injection
  • Potential to generate additional revenue, reduce

emissions and augment longer term pipeline plans

  • Oil trucked to market (up to 40 MBopd)
  • Low ~$3.15 oil differential to WTI through 2018
  • Gas combusted under appropriate permits
  • Building out field gathering infrastructure; centralized

tank battery used for processing, storage and export

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SLIDE 19

APPENDIX

18

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SLIDE 20

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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) $3.1 $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

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SLIDE 21
  • 1

1 dual XRL: : (equivalent to 4 single laterals)

  • 1 full section

ion develop velopmen ent: : (equivalent to 3 single laterals)

  • 1 coplan

lanar: ar: (equivalent to 2 single laterals)

  • 2 XRLs: Record low of $1.3MM Avg D&C

(equivalent to 4 single laterals)

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2016 Mississippian program: 13 laterals

$1.7MM Avg D&C per Lateral, 100% Multi and XRL

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SLIDE 22

21

Durable Mississippian Economics

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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SLIDE 23

Year End 2016 Reserves and PV-10

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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.

www.sandridgeenergy.com

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SLIDE 24

Four Quarters of Trailing Actuals

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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

  • Adj. G&A – Cash2

$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.

www.sandridgeenergy.com

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SLIDE 25

2017 Capital Expenditures Guidance

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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

www.sandridgeenergy.com

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SLIDE 26

2017 Operational Guidance

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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

  • 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

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SLIDE 27

26

Hedging Overview

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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SLIDE 28

Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10

27 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.