Final march ir presentation 3.24.17

1. INVESTOR
PRESENTATION
MARCH 2017

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, 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.
2
Forward Looking Statement
www.sandridgeenergy.com

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 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.
3 www.sandridgeenergy.com
- >$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

4. 4
SandRidge Energy Overview
Unlevered oil producer focused on resource value creation
KEY INFORMATION
Market Equity Value as of Mar 20, 2017
35.9 MM common shares $638 Million
Primary Assets 2P Locations1
Net Acres
Mississippian
Anadarko Basin, OK
~300 400k
NW STACK
Anadarko Basin, OK
Under
Evaluation
60k
Niobrara Shale
North Park Basin, CO
~1,300 132k
Production & Reserves
Q4’16
Production 47.2 MBoepd (28% oil)
YE’16
Proved 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.

5. 5
STACK Activity Moving Northwest
Increasing 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:

6. 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

7. 7
NW STACK – Meramec and Osage
SandRidge 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

8. 8
Activity Proving Out NW STACK
17 Rigs running, many producing wells now near SD NW STACK acreage

9. 9
NW STACK Acquisition
Acquisition 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

10. 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)
10
High-Grade + Innovation = Value Creation
2016 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

11. 11
Durable Improvement in Mississippian Economics
Multis and XRLs support continued harvest of remaining high-graded inventory
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

12. 12
Mississippian Recoveries Improving
High-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 RATIO
2013 2014 2015 2016
7 7 6 2
PROJECTED EURS
NORMALIZED BY LATERAL

13. 13
• 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 Overview
Dominant 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

14. 14
Initially Targeting Lower Niobrara
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%

15. 15
SandRidge Niobrara Shale Advancements
Lowered 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

16. 16
North Park Laterals Outperforming Cumulative Oil Type Curve
11 SandRidge Laterals in 2016 outperforming type curve by 9%

17. 17
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

18. 18
Niobrara Asset Midstream Status
Oil currently trucked at low differential to WTI
NORTH PARK BASIN
POTENTIAL 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

19. APPENDIX
19

20. 20
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
85%
1,350
20%
550
20%
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

21. 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) 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 9,210
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
Historical realized + 3.20.17 NYMEX Pricing (~$50 / ~$3)
55,686 37,687 521,173 180,235 $763_
Year End 2016 Reserves and PV-10
21
(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

22. $638MM
COMMON
EQUITY
$425MM
BORROWING BASE
$417MM available
($8MM LOCs)
UNDRAWN
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
~$120MM CASH
2
22
$618MM
PDP PV10
$145MM
PUD PV10
$763MM OF PROVEN
PV-10 AT STRIP1
Zero Net Debt
0.0x net leverage
STRONG LIQUIDITY
(1) Strip PV-10 of YE’16
proved reserves and
Share Price at 3.20.17
strip pricing and close
(2) Cash as of February
23rd

23. 2017 Capital Expenditures Guidance
23
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

24. 2017 Operational Guidance
24
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

25. Hedging Overview
25
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 $55.34
NATURAL GAS Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018
SWAPS
Volumes (Bcf) 8.10 8.19 8.28 8.28 32.85 0.90 0.91 0.92 0.92 3.65
Price ($/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
www.sandridgeenergy.com

26. Reconciliation of Standardized Measure of
Discounted Net Cash Flows to PV-10
26 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.