final march ir presentation 3.24.17

INVESTORPRESENTATIONMARCH 2017

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Cautionary StatementsThis 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, operational optimization initiatives anticipated efficiency and cost reductions, the acquisition of seismic data, infrastructure investment, liquidity, capital structure, hedging position, 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 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 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.

Forward Looking Statement

www.sandridgeenergy.com

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SandRidge EnergyWith a strong balance sheet, we have built a portfolio of three project areas with competitive project IRRs and significant location inventories. Investment will continue the high-graded harvest of our Mississippian position, and development of both our NW STACK and North Park Niobrara oil projects, with total company oil production turning the corner in late 2017.


- >$500MM of liquidity including ~$120MM cash

- Moderate level of outspend

- Protect the balance sheet

- High-graded harvest - Competitive project

IRRs- 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 - ~60k net acres in 3

counties • Major (30k net acres)• Woodward (20k net acres) • Garfield (10k net acres)

- Increased oil exposure

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SandRidge Energy OverviewUnlevered oil producer focused on resource value creation

KEY INFORMATIONMarket Equity Value as of Mar 20, 201735.9 MM common shares $638 Million

Primary Assets 2P Locations1 Net Acres

MississippianAnadarko Basin, OK

~300 400k

NW STACK Anadarko Basin, OK

Under Evaluatio

n60k

Niobrara ShaleNorth Park Basin, CO ~1,300 132k

Production & Reserves Q4’16Production

47.2 MBoepd (28% oil)

YE’16Proved Reserves2

180 MMBoe (31% oil)$763MM Strip PV-10

(1) 2P locations: Undeveloped Proved and Probable(2) SandRidge reserves and PV-10 as of 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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STACK Activity Moving NorthwestIncreasing activity supports enthusiasm around Major, Woodward, and Garfield Co. NW STACK

• Multiple operators with NW STACK Meramec and Osage results

• 17 rigs currently running

• Over 50 producing wells in Major, Woodward, and Garfield

• More than 100 permitted wells in Major, Woodward, and Garfield

INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE

Industry activity has been converging on existing SD acreage with prominent operators seeing encouraging results:

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NW STACK Primary TargetsNW STACK Meramec and Osage same productive formation as in STACKStructurally 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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NW STACK – Meramec and OsageSandRidge has operated in and around the NW Stack for many years

2016 Meramec and Osage program• Medill 1-27H, Major Co., Meramec • Keeton 1-24H, Major Co., Osage• Charlene 1-29H, Garfield Co.,

Meramec

Osage drilled in Garfield Co. in 2014-15• Benkendorf and Henry wells average

30-Day IP of 618 Boepd (74% oil)

Successful track record in Oklahoma• Operating in area for more than seven

years developing nearby Miss Lime and Chester

• Low cost operator, realizing as low as$1.3MM of D&C per lateral in Miss Lime

• Over 1,600 wells drilled

SANDRIDGE ACTIVITY ACROSS 3 COUNTIES

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Activity Proving Out NW STACK17 Rigs running, many producing wells now near SD NW STACK acreage

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NW STACK AcquisitionAcquisition increases our NW STACK position to 60k net acres

• Complements surrounding SD NW STACK acreage

• Stacked pay of Meramec and Osage • Adds locations with competitive IRRs at strip• ~700 Boepd of production• 88% operated w/ minimal near term acreage

expiries

CONTIGUOUS ~13.1K NET ACRES FOR $48MM CASH

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Lateral$1.7MM Avg D&C per• 1 dual XRL:

(equivalent to 4 single laterals)• 1 full section development:

(equivalent to 3 single laterals)

• 1 coplanar: (equivalent to 2 single laterals)

• 2 XRLs: Record low of $1.3MM Avg D&C (equivalent to 4 single laterals)

High-Grade + Innovation = Value Creation2016 Mississippian program: 13 laterals, 51% IRR1

(1) Estimated based on historical realized pricing + 2.10.17 NYMEX Strip and actual production + forecasted production

100% Multi and XRL

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Durable Improvement in Mississippian EconomicsMultis and XRLs support continued harvest of remaining high-graded

inventory

D&C CAPEX, $MM PER LATERAL43% Lower costs per lateral vs. 2014

90-DAY CUMULATIVE MBOE PER LATERALResults shown by groups of 25

wells

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Mississippian Recoveries ImprovingHigh-graded harvest resulting in more consistent results

• High-grading results in improving EUR trend

• Realizing tighter EUR distributions (P10 / P90)

• Remaining Mississippian locations form reliable inventory

P10 / P90 RATIO2013 2014 2015 2016

7 7 6 2

PROJECTED EURSNORMALIZED BY LATERAL

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• XRLs currently below $7.0MM D&C (<$3.5MM per lateral) with projected 600 MBoe EUR and targeting sub-$3.5MM per lateral in 2017

• Ten wells drilled in 2016 including one XRL and one “C” bench target

• 60 drilling permits approved

• 30 MMBoe of proved reserves1 (87% oil)

• Federal units largely eliminate near term HBP drilling requirements, 71k net acres currently held by production or unit (54%)

North Park Niobrara Asset OverviewDominant acreage position with high oil cut

(1) SandRidge reserves as of 12.31.16, based on SEC pricing ($42.75 / $2.48)

• 1,300 2P Locations• 132k Net acres

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Initially Targeting Lower NiobraraSimilar 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 ThicknessPorosity

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 PressureGas-oil Ratio (GOR)Total Organic Content

> 0.55 psi/ft600 – 700

scf/stb3%

0.41 - 0.60 psi/ftUp to 10,000+

scf/stb3%

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SandRidge Niobrara Shale AdvancementsLowered costs, optimized completions, drilled an XRL, confirmed stacked pay

Improved drilling and completion designs• Eliminated intermediate casing • Oil based mud utilized for improved drilling times and

hole stability• Confirmed crosslinked gel fracs yield consistent well

results; seven crosslink gel wells above type curve• Slickwater fracs led to lower initial oil rates and higher

water cuts due to large volume of water pumped

Drilled the first XRL in the basin• 2-mile lateral drilled and completed for $3.4MM D&C per

lateral with a 30-Day IP of 901 Boepd (91% oil)

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

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

• Nine additional wells targeted the “D” bench Note: 30-Day IP rates shown above

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North Park Laterals Outperforming Cumulative Oil Type Curve

11 SandRidge Laterals in 2016 outperforming type curve by 9%

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North Park Laterals Outperforming Oil Type Curve

Average oil rate of all 11 laterals drilled by SandRidge in 2016

11 SD Laterals in 2016:• Average free flowing period of

two to three months

• Earlier installation of artificial lift

in future to optimize production

• All laterals currently on either jet pump, gas lift, or rod pump lift mechanisms

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Niobrara Asset Midstream StatusOil currently trucked at low differential to WTI

NORTH PARK BASINPOTENTIAL PIPELINE ROUTESCurrent Oil and Gas Disposition

• Building out field gathering infrastructure; centralized tank battery used for processing, storage and export

• Oil trucked to market (centralized oil loading bay could handle 40 MBopd)

• Gas combusted under appropriate permits

Strategic Options• Removing liquids from gas stream• Oil and gas pipelines under evaluation• Currently proceeding with engineering,

permitting and right-of-way acquisition for oil and natural gas pipelines

• Gas reinjection being considered to reduce combustion volumes

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APPENDIX

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2017 Project EURs, Economics, & Inventory

EURs & Economics

Meramec Niobrara Mississippian

XRL* Single XRL FSD* Single

EUR, MBoe % Oil

800 – 1,00040%

500 – 600 40%

60085%

1,350 20%

55020%

D&C per lateral ($MM) $3.1 $4.2 $3.4 $2.0 $2.4

IRR(a) 24 - 42% 19 - 31% 33% 65% 17% PV-10(a) ($MM) $2.4 - $4.7 $1.0 - $2.1 $3.4 $5.5 $0.5

YE’16 Inventory NW STACK Niobrara Mississippian PUDs (laterals) 6 106 51(b)

Probables (laterals) Under evaluation(4-8 per section is standard)

~1,180 ~180(b)

Net acres 60k 132k 400k HBP 27% 54% 74%

a) @ Feb 10th Strip pricing (~$55 /~$3.00)b) Excluding ~70 Proven + Probable Chester locations

Diverse and material location inventory in three active areas

*FSD = “Full Section Development”, equivalent to 3 laterals*XRL = “Extended Reach Lateral”, 2-mile lateral

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Year End 2016 Reserves and PV-10 Proved Reserves Oil

MBblsNGLsMBbls

GasMMcf

EquivalentMBoe1

PV-102

$MMProved 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 9,210Proved 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.


$638MM COMMON

EQUITY $425MM BORROWING

BASE$417MM available

($8MM LOCs)

UNDRAWN

(1) Strip PV-10 and Share Price at 3.20.17

Market Capitalization and Liquidity

$36MM BUILDING NOTE

35.9 MM common shares outstanding at $17.78 per

share1

• $600MM committed• First redetermination Oct

2017 • March 2020 maturity

(2) Cash as of February 23rd

~$120MM CASH2

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$618MM PDP PV10

$145MM PUD PV10

$763MM OF PROVEN PV-10 AT STRIP1

Zero Net Debt0.0x net leverage

STRONG LIQUIDITY

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2017 Capital Expenditures Guidance CAPEX GUIDANCE DETAIL $MM Mid-Continent D&C $65 - $70 North Park D&C 20 - 25 Other - D&C1 24Total Drilling & Completion $109 -

$119 OTHER E&P Land, G&G and Seismic $40 Infrastructure2 7 Workovers 37 Capitalized G&A and Interest 15Total 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 99Total Exploration and Production $208 - $218

General Corporate 2Total 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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2017 Operational GuidanceTOTAL COMPANY PRODUCTION

Oil (MMBbls) 4.0 – 4.2Natural Gas Liquids (MMBbls) 3.0 – 3.2

Total Liquids (MMBbls) 7.0 – 7.4Natural 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 REVENUESeverance 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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Hedging Overview

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) $52.2

4$52.2

4$52.2

4$52.2

4 $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 0.90 0.91 0.92 0.92 3.65 Price ($/Mcf) $3.20 $3.20 $3.20 $3.20 $3.20 $3.12 $3.12 $3.12 $3.12 $3.12

Note: As of 2.22.17


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


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 SuccessorDec 31, 2016

PredecessorDec 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.

final march ir presentation 3.24.17

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