- SandRidge plans to spend under $200 million in 2017 developing its assets in the Mid-Continent and North Park Basin regions. - In the Mid-Continent, the company will appraise and develop the Meramec and Osage formations through extended reach lateral drilling in three Oklahoma counties with potential to add significant proved undeveloped reserves. - In the North Park Basin, SandRidge aims to delineate the Niobrara oil resource through a program of exclusively extended reach laterals, with a goal of achieving per-lateral drilling and completion costs below $3 million.

1. INVESTOR
PRESENTATION
JANUARY 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, 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 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 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
- Over $500MM of Liquidity
- Moderate Level of
Outspend
- Protect the Balance Sheet
- Long Runway
- High-Graded Harvest
- Competitive Project IRRs
- Adjacent Zone Drilling
(Meramec/Osage)
- Continue to Drive Down
Costs
- Produce Consistent Well
Results
- Innovate on Well Designs
- Dominant North Park
Position
- Long Term Oil Growth
- Expands Drilling
Inventory
- 1,300 2P Locations
- Additional Zones
- Extended Reach Laterals
(“XRL”) & Multilaterals
(“Multi”)
- New Areas
- Pioneering Technologies

4. 4
SANDRIDGE ENERGY OVERVIEW
UNLEVERED OIL PRODUCER FOCUSED ON RESOURCE VALUE CREATION
KEY INFORMATION
FULLY DILUTED MARKET EQUITY VALUE @ $24 / SHARE
20.6 MM Common shares +
14.8 MM Conversion shares
= Estimated Market Cap
$494 Million +
$ 355 Million
= $850 Million
PRIMARY ASSETS
Mid-Continent
Focus Area
458k
Net Acres
~300 2P1
Locations
(includes prospective
Meramec/Osage)
(excludes prospective
Meramec/Osage)
North Park Basin
Niobrara Oil
133k
Net Acres
~1,300 2P1
Locations
PRODUCTION & RESERVES
Q3’16 Production 49.6 MBoepd2
(28% oil)
SEC Proved
Reserves
281 MMBoe at YE’153
(25% oil)
138 MMBoe at Q3’16
~20% higher at recent strip pricing
(1) 2P locations: Undeveloped Proved and Probable
(2) Excludes production related to noncontrolling interests
(3) 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)

5. CREATING RESOURCE VALUE IN TWO BASINS
5
• High-graded harvest and expansion of our Mid-Continent asset
• Q4’16 Miss XRLs reduce 2016 average D&C from $1.9MM to $1.7MM per lateral,
supporting competitive IRRs at Dec 2016 strip
• ~1,300 producing horizontal wells, 3D seismic and improved reservoir characterization
• One rig active most of 2016 and 2017, with Miss and Meramec/Osage focus
– Production decline moderating as 2014-15 producers mature
• Industry leading well costs and innovative multi and XRL development
• Drilling adjacent plays including Meramec/Osage focused counties: Garfield, Major, and Woodward
• Industry activity moving north and west surrounding our position
• Growth in oil reserves and anticipated value per barrel via North Park Niobrara development
• Achievable well costs (sub-$3MM per lateral D&C in 2017) support competitive IRRs
• 1,300 proved and probable locations with significant near term PUD potential
• 100% XRL program in 2017
• Upside through more Niobrara benches, completion and spacing optimization, and lower well costs
• Net unlevered balance sheet1 and strong liquidity provides financial flexibility
– ~$536MM liquidity, ~$111MM of unrestricted cash, & undrawn $425MM revolver2
• Sub-$200MM 2017 CAPEX plan: 1 rig for part of year in each of Mid-Continent and Niobrara
• ~55% reduction in workforce since beginning of 2016
(1) Excluding mandatorily convertible notes
(2) Pro Forma for debt pay down following emergence on 10.4.16 and excludes approximately $10MM of LOCs
HARVEST &
APPRAISE
MID-CONTINENT
HIGH-GRADE
PLUS ADJACENT
MERAMEC/OSAGE
DRILLING IN THREE
COUNTIES
DIVERSIFY
GROW OIL RATE AND
RESERVES IN NIOBRARA
UN-LEVERED
STRONG FINANCIAL
POSITION

6. 6
SUB-$200MM 2017 CAPEX TARGETS ATTRACTIVE IRRS
PLUS 2017 PUD ADDITIONS IN BOTH MID-CONTINENT AND NIOBRARA
• Finish 2016’s successful high-graded Miss program
– Late 2016 Miss XRLs (4 laterals total) at <$1.5MM D&C per lateral
– Drilling technology and well cost reduction focus transfer to both
Meramec /Osage and Niobrara
• Appraise and confirm Meramec/Osage potential in three counties
– Major, Garfield, and Woodward Counties
– Potential for material PUD additions in 2017
• Develop and delineate North Park Niobrara Oil resource
– Sub-$3MM D&C per lateral targeted in 2017 program (100% XRLs)
– Potential for material PUD additions in 2017

7. 7
2017 MERAMEC/OSAGE PROGRAM IN 3 OKLAHOMA COUNTIES
POTENTIAL TO ADD MATERIAL LOCATIONS THROUGH MERAMEC/OSAGE DEVELOPMENT
• Garfield Co: 1 Meramec well and 3
Osage wells producing in Garfield to be
followed up by 1 Meramec XRL in 2017
• Major Co: 2 drilled wells confirmed
Meramec and Osage production, to be
followed up by 4 Meramec XRLs in 2017
• Woodward Co: Test Meramec/Osage in
2017 with 1 XRL adjacent to peer
production2017 activity supports
appraisal of three counties
INDUSTRY ACTIVITY
ADJACENT TO SD ACREAGE
INDUSTRY ACTIVITY IS CONVERGING
ON EXISTING SANDRIDGE ACREAGE
SD Meramec/Osage
activity in 3 counties:

8. 8
• SandRidge is a leading producer in the Mid-Continent
• Stacked reservoirs on large acreage base
– Mississippian
– Chester/Manning
– Meramec/Osage gaining industry attention
• Miss Lime has been primary target
– +/- 300’ thick carbonate at ~6,000’ TVD
– Over 1,600 horizontal wells drilled in OK & KS since
2010
• Salt water disposal infrastructure
– 1,095 miles of pipeline, connected to 136 active
disposal wells
• Electrical infrastructure
– 1,250 miles of power lines, six substations and two
micro grids
MID-CONTINENT OVERVIEW
458K NET ACRES IN OKLAHOMA, WITH MISSISSIPPIAN, CHESTER, AND MERAMEC/OSAGE PRODUCTION
KS
OK

9. 9
DURABLE IMPROVEMENT IN ECONOMICS
MULTIS AND XRLS ARE A BREAKTHROUGH IN MISSISSIPPIAN
D&C CAPEX, $MM PER LATERAL
Lower costs per lateral
-43% vs 2014
90-DAY CUMULATIVE MBOE PER LATERAL
Results shown by groups of 50 wells

10. 10
MISSISSIPPIAN RECOVERIES IMPROVING
HIGH-GRADE YIELDING TIGHTER EUR DISTRIBUTIONS WITH BETTER RESERVOIR CHARACTERIZATION
• High-graded harvest resulting in
more consistent results
• Remaining Mississippian
locations form reliable inventory
• Multi and XRL costs per lateral
support competitive returns
P10 / P90 RATIO
2013 2014 2015 2016
7 8 7 2
PROJECTED EURS
NORMALIZED BY LATERAL

11. $1.7MM Avg D&C per Lateral
• 2 XRLs:
(equivalent to 4 single laterals)
• 1 dual XRL:
(equivalent to 4 single laterals)
• 1 full section development:
(equivalent to 3 single laterals)
• 1 coplanar:
(equivalent to 2 single laterals)
11
2016 MISSISSIPPIAN VALUE CREATION
MULTIS AND XRLS REDUCE COSTS AND PRESERVE COMPETITIVE RETURNS AT LOWER COMMODITY PRICES
(1) Estimated based on historical realized pricing + 12.19.16 NYMEX Strip and actual production + forecasted production
2016: 13 Miss laterals
51% IRR1
100% Multi and XRL

12. 12
• XRLs of $7.0MM D&C Capex ($3.5MM per lateral)
with projected 600 MBoe EUR and targeting sub-
$3MM per lateral in 2017
• Eleven laterals drilled in 2016 including one XRL
• 60 drilling permits approved
• 28 MMBoe of proved reserves1 (81% oil); 108 PUDs
• Federal units largely eliminate near term HBP
drilling requirements, ~75k net acres currently held
by production or unit (56%)
• Additional 33k net acres proposed to be held by
unit by year end 2017, for a total of ~108k net acres
held by unit or production (81%)
NORTH PARK NIOBRARA ASSET OVERVIEW
DOMINANT ACREAGE POSITION WITH HIGH OIL CUT
(1) SandRidge reserves as of 12.31.15, based on SEC pricing ($46.79 / $2.59)

13. 13
NIOBRARA DRILLING ECONOMICS
REDUCING COSTS $500K PER LATERAL SUPPORTS LARGE IRR UPSIDE;
CURRENT COSTS ACHIEVED AFTER JUST 11 LATERALS INCLUDING ONLY 1 XRL
Assumptions:
XRL $7.0MM D&C cost ($3.5MM per lateral), 600 MBoe EUR
XRL
CURRENTLY $3.5MM PER LATERAL
Targeting <$3.0MM
per lateral
Current $3.5MM
per lateral
Reducing cost per lateral of
XRLs will be a priority in 2017

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 % 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%

15. 15
2016 SANDRIDGE NIOBRARA RESULTS
478 BOEPD (90% OIL) AVERAGE 30-DAY IP ON FIRST FIVE SANDRIDGE LATERALS
DESIGNED TO TEST
• Cycle time reduction
• XRL
• Additional bench
• Spacing
• Stimulation methods
• Artificial lift methods
SIX LATERALS ONLINE IN LATE 2016FIRST FIVE SANDRIDGE LATERALS
Initial results of 2H’16 wells to
be released with Q4’16 earnings

16. 16
GREGORY 1-9H,
550 BOEPD (89% OIL) 30-DAY IP
FIRST SANDRIDGE NIOBRARA LATERAL
THE GREGORY 1-9H CONTINUES TO OUTPERFORM TYPE CURVE
Cumulative production
of 82 MBo at 250 Days

17. 17
NIOBRARA TYPE CURVE SUPPORT
AVERAGE OIL RATE OF FIRST FIVE SANDRIDGE LATERALS DRILLED
FIRST 5 SANDRIDGE
LATERALS
• Outperforming type curve
• Free flowed for over three months
• First three laterals currently on
artificial lift
• Optimizing production by
accelerating artificial lift on future
installations
• Installing artificial lift on all
remaining 2016 laterals in Q1’17

18. 18
LAST 14 LATERALS USING MODERN COMPLETION DESIGNS
14 LATERALS SUPPORTING TYPE CURVE CUMULATIVE OIL
Average Cumulative Oil
126,298 Bbls
96,917 Bbls
Cumulative Type Curve Oil

19. 19
ACHIEVABLE UPSIDE IN NIOBRARA
LOWER COSTS, OPTIMIZED COMPLETIONS, XRLS, STACKED PAY AND LOCATION COUNT
HBP AND FEDERAL UNITS HOLD 56% OF ACREAGE
UPSIDE INCLUDES
• Successfully drilling XRLs; first 2-mile lateral drilled and
completed in Q3’16 and brought online in Q4’16
• Proving up additional benches
– 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
• Expanding structural and geologic reservoir
characterization model beyond existing 54 square miles of
3D seismic by acquiring additional 64 square miles of 3D
seismic starting in 2017
• Optimizing completions to enhance production rate and
ultimate recovery, while reducing costs
• Reducing drilling and completion costs through applied
learnings and observing DJ Basin operators

20. 20
NIOBRARA ASSET MIDSTREAM STATUS
WTI OIL DIFFERENTIAL HAS BEEN REDUCED FROM $11+/BBL TO $3.15/BBL
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
MIDSTREAM STRATEGIC OPTIONS
• Reduce air emissions by removing liquids from gas
stream with gas reinjection being considered to
reduce combustion volumes
• Oil and gas pipelines under evaluation
– Currently proceeding with engineering, permitting
and right-of-way acquisition for oil and natural gas
pipelines
Plains Rocky
Mountain Pipeline
Rockies Express
Pipeline (REX)
Colorado Interstate
Gas Pipeline (CIG)

21. APPENDIX
21

22. THE REORGANIZED SANDRIDGE ENERGY AS OF OCT. 31ST
22
COMMON
EQUITY
MANDATORILY
CONVERTIBLE
DEBT
$425MM
REVOLVING
CREDIT
FACILITY
$111MM CASH
$536MMLiquidity
• 20.6 MM common shares outstanding
• 14.8 MM issuable upon conversion of mandatorily convertible debt
• 4.9 MM warrants at $41.34 strike price
• 2.1 MM warrants at $42.03 strike price
• $278MM1 face value
• Unsecured and mandatorily convertible into 14.8 MM shares
• No interest2
• Undrawn3
• Minimal covenants or borrowing base redeterminations for two years
• LIBOR (100 bps floor) + 475 bps rate
• $111MM in unrestricted cash
(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 on 10.4.16 and excludes approximately $10MM of LOCs
Note: In addition to the items above there is a $35MM note secured by the Company’s non-oil and gas real property
net share settled

23. NEW SANDRIDGE CAPITAL STRUCTURE
23 www.sandridgeenergy.com
$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) -
Unsecured Notes:
8.75% Senior Unsecured Notes due 2020 $ 396 $ (396) $ -
7.50% Senior Unsecured Notes due 2021 758 (758) -
8.125% Senior Unsecured Notes due 2022 528 (528) -
7.50% Senior Unsecured Notes due 2023 544 (544) -
Sub-Total Unsecured Notes $ 2,225 $ (2,225) $ -
Unsecured Convertible Notes:
8.125% Senior Unsecured Convertible Notes due 2022 $ 41 $ (41) $ -
7.50% Senior Unsecured Convertible Notes due 2023 47 (47) -
Total Senior Debt $ 3,641 $ (3,606) $ 35
0.00% Mandatorily Convertible Senior Subordinated Notes2 - 278 278
Total Debt $ 3,641 $ (3,328) $ 313
Liquidity
RBL Borrowing Base3 $ 500 $ (75) $ 425
RBL Available - 425 425
Cash 634 (523) 111
Total Liquidity $ 634 $ (98) $ 536

24. 2016 OPERATIONAL GUIDANCE
24
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.

25. 2016 CAPITAL EXPENDITURES GUIDANCE
25
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

26. HEDGING OVERVIEW
26
OIL Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018
SWAPS
Volumes (MMBbls) 1.29 0.63 0.64 0.64 0.64 2.56 0.27 0.27 0.28 0.28 1.10
Price ($/Bbl) $56.45 $51.45 $51.45 $51.45 $51.45 $51.45 $55.10 $55.10 $55.10 $55.10 $55.10
NATURAL GAS Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017
SWAPS
Volumes (Bcf) 10.92 7.20 7.28 7.36 7.36 29.20
Price ($/Mcf) $2.86 $3.19 $3.19 $3.19 $3.19 $3.19
BASIS SWAPS (PEPL)
Volumes (Bcf) 0.92 NA NA NA NA NA
Price ($/Mcf) ($0.38) NA NA NA NA NA
Note: As of 11.08.16