SANDRIDGE ENERGY INC - FORM 8-K - EX-99.2 - May 16, 2016

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SandRidge Energy, Inc.
Company Overview
February 2016
Exhibit 99.2

Disclaimer
This
presentation
regarding
SandRidge
Energy,
Inc.
and
its
subsidiaries
(“SD”
or
the
“Company”)
has
been
prepared
solely
for
informational
purposes
using
certain
Company
information
and
publicly
available
information.
Neither
the
Company
nor
any
of
its
advisors
or
representatives
makes
any
representation
or
warranty,
express
or
implied,
as
to
the
accuracy
or
completeness
of
the
information
in
this
presentation,
and
nothing
contained
herein
is,
or
should
be
relied
on
as,
a
promise
or
representation,
whether
as
to
the
past
or
the
future.
The
presentation
includes
certain
statements,
estimates,
and
projections
with
respect
to,
among
other
things,
the
anticipated
operating
performance
of
the
Company,
which
are
inherently
subject
to
significant
economic,
competitive,
and
other
uncertainties
and
contingencies
and
have
been
included
solely
for
illustrative
purposes.
This
presentation
speaks
as
of
the
date
on
which
it
is
made.
Neither
the
delivery
of
this
presentation
nor
any
further
discussions
with
the
Company
or
any
of
its
advisors
or
representatives
shall,
under
any
circumstances,
create
any
implication
that
there
has
been
no
change
in
the
affairs
of
the
Company
since
that
date.
Neither
the
Company
nor
any
of
its
advisors
or
representatives
undertakes
any
duty
to
update
or
to
correct
this
presentation.
This
presentation
is
not
intended
to
furnish
regulatory,
tax,
accounting,
investment,
restructuring,
or
any
other
advice
to
any
recipient.
This
presentation
has
been
prepared
without
taking
into
account
individual
investment
objectives,
financial
situation,
or
needs
of
any
particular
person.
The
statements
and
information
contained
in
this
presentation
that
are
not
statements
of
historical
fact,
including
any
estimates
and
assumptions
contained
herein,
are
"forward
looking
statements"
as
defined
in
Section
27A
of
the
Securities
Act
of
1933,
as
amended,
and
Section
21E
of
the
Securities
Exchange
Act
of
1934,
as
amended.
These
statements
are
qualified
in
their
entirety
by
the
"Risk
Factors,"
"Management's
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations,"
and
all
other
applicable
sections
of
the
Company's
2014
annual
report
on
Form
10-K
filed
with
the
Securities
and
Exchange
Commission
and
subsequently
filed
quarterly
reports
on
Form
10-Q.
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Introduction……………………………………………………………………………………………
Reserves…………………………………………………………………………………………………
Core Assets
Mississippian..……………………………………………………………………………………..
North Park Basin………………………………………………………………………………….
Other Assets…………………………………………………………………………………………..
Appendix………………………………………………………………………………………………
4
8
14
20
26
28
Page
Table of Contents
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Introduction

Business Highlights
Experienced Developers with
Culture of Innovation and Continuous Improvement
Solid Base Returns /
Substantial Upside
MidCon provides derisked production base with high graded drilling inventory, under current pricing
Growth potential with recent North Park acquisition and continued MidCon improvements
Upsides: well costs, deployment of extended and multi laterals into North Park Basin (NPB), stacked zones
in MidCon and NPB, NPB type curve and stimulation methods
Deep Operating
Experience
Large scale efficient operator: Over 1,600 horizontal wells; 30+ rigs in 2014; market leading cost of
$2.2MM per Mississippian lateral
Infrastructure and logistics: building and optimizing extensive midstream and electrical systems
Artificial lift: optimizing well returns via gas lift, ESPs, and rod pumps
Engineering: pioneering application of multilaterals, extended laterals, full section development and new
completion techniques to reduce costs and enhance recovery
Business Minded
Management Team
Management background includes oil majors, independents and Wall Street
Prudent management strategy to increase asset value through innovation and cost reduction
Focused on asset base diversification and increasing oil mix; focused on fully loaded returns
Positioned to Capitalize on
Market Opportunities
Strong tenured team focused on results and value.  Proactive during the downturn with improved
operating metrics, focus on capital efficiency and successes eliminating contractual and business
overhang issues
Ability to deploy skillsets into adjacent assets and selected consolidation opportunities
Near Term Objectives
Top decile in all operational execution measures
Fierce capital discipline targeting a minimum 10% fully burdened IRR at strip
Drive costs down further in MidCon, become cost leader in Niobrara
Initiate Niobrara development targeting 12k bopd into 2017
Keep cost structure in-line with activity level
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Asset Overview
E&P Assets
Midstream
SWG System
Electrical System
Compressors, Other
Non-Oil & Gas Real Estate
Corporate HQ, Other OKC Properties
Non-E&P Assets
* Lariat Services activities significantly reduced
Dec ’15 Production: 1.0 Mboe/d
1P Reserves:
25 MMboe
Dec ’15 Production: 3.7 Mboe/d
1P Reserves
(1)
:
7
MMboe
Dec ’15 Production: 58.3 Mboe/d
1P Reserves
(1)
:
261 MMboe
(1)
Net of NCI portion of royalty trusts
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2016 Focus
Drilling Plan
Rig Count
Laterals Spud
Focused on enhancing MidCon returns while establishing North Park and protecting liquidity
Flexible capital spending program designed to adjust with market environment
Prudently reduced MidCon rig count with high graded targets and lower well costs
Concentration on highest return focus areas
Utilizing reservoir and geologic modeling
1 rigs planned in MidCon for remainder of 2016
Cost reductions from multi lateral full section development and extended lateral designs
Quickly establish best practices in North Park development
Drive down well costs
Improve recovery through enhanced completion techniques
Production
Mboed
FY-16 Total
32 Laterals
FY-16 Total
22 Laterals
62.6
55.1
50.5
46.8
63.2
56.6
53.0
50.3
Q1-16
Q2-16
Q3-16
Q4-16
MidCon
Rockies
Total
12
7
6
7
4
5
7
6
Q1-16
Q2-16
Q3-16
Q4-16
MidCon
Rockies
2
1
1
1
1
1
1
1
Q1-16
Q2-16
Q3-16
Q4-16
MidCon
Rockies

Reserves

Asset Map
Strong production base with platform for growth –
$2.1 billion of 2P NPV & 1.0 Bboe
Summary of Assets by Location
Dec ’15 Production: 3.7 Mboe/d
1P Reserves
(1)
:
7
MMboe
1P PV-10
(1)(2)
:
($20MM)
Dec ’15 Production: 58.3 Mboe/d
1P Reserves
(1)
:
261 MMboe
1P PV-10
(1)(2)
:
$1,131MM
Dec ’15 Production: 1.0 Mboe/d
1P Reserves:
25 MMboe
Acquisition Value:
~$190MM
(1)
Net of NCI portion of royalty trusts
(2)
As of 1/29/16 strip; $37.45 / $2.43 (2016), $43.79 / $2.75 (2017), $46.30 / $2.88 (2018), $48.00 / $2.99 (2019), $49.32 / $3.11 (2020)
Totals
1P
2P
Reserves (MMboe)
(1)
293
1,005
PV-10 ($MM)
(1)(2)
$1,105
$2,128
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Core
Emerging
Non-Core
Mississippian
Chester
North Park Basin
Woodford &
Meramec
Permian
Reserves (Mboe)
(1)(2)
255,246
3,860
24,710
1,444
7,455
PV-10
($MM)
(1)(2)
$1,088
$33
~$190
(3)
$10
($20)
Dec
’15 Production
(Mboe/d)
56.4
1.2
1.0
0.7
3.8
Overview of Reserve Assets
Note:
(1)
Proved reserves net of NCI portion of royalty trusts
(2)
As of 1/29/16 strip; $37.45 / $2.43 (2016), $43.79 / $2.75 (2017), $46.30 / $2.88 (2018), $48.00 / $2.99 (2019), $49.32 / $3.11 (2020)
(3)
Reflects North Park acquisition value
Mississippian reserve base supported by growth potential in Chester and North Park
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Note:
Based on SEC reserve report run at 1/29/16 strip; assumes well costs of: Miss@$2.4MM; Chester@$2.8MM; North Park@$4MM; Woodford@$3.1MM
1/29/16 strip: $37.45 / $2.43 (2016), $43.79 / $2.75 (2017), $46.30 / $2.88 (2018), $48.00 / $2.99 (2019), $49.32 / $3.11 (2020)
Net of NCI portion of royalty trusts
Technical PUDs: Proved undeveloped locations which fit the geologic risk profile of SEC PUDs but excluded from actual SEC PUDs due to 5  year development rule or other limitations
(1) North Park Undeveloped PV-10 includes facilities costs of $41MM
Reserve volumes are 79% developed and 24% oil
Reserves & PV-10 By Area @ Jan 29, 2016 Strip Pricing
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Competitive Returns in Depressed Commodity Environment
IRR Comparison: D&C Only
IRR Comparison: “All-In”
($MM)
D&C
Non-D&C
(1)
Total “All-In”
Mississippian
$2.1
$0.5
$2.6
North Park
$3.6
$0.1
$3.7
Note: Blended type curve reflects 2016 Mississippian drilling program
(1)
Non-D&C costs include undiscounted: Midstream and Electrical ($55k), SWG ($120k), and Workovers ($320k)
Competitive returns at both D&C and “All-In” cost in low commodity price environment
13%
17%
22%
10%
16%
23%
0%
5%
10%
15%
20%
25%
30%
35%
1/29 STRIP
1/29 STRIP (OIL + $5)
1/29 STRIP (OIL + $10)
Miss (Blended)
North Park
20%
26%
32%
11%
17%
24%
0%
5%
10%
15%
20%
25%
30%
35%
1/29 STRIP
1/29 STRIP (OIL + $5)
1/29 STRIP (OIL + $10)
Miss (Blended)
North Park
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Acreage Summary
Significant HBP acreage, with expiring acreage largely being Kansas non-core
Notes:
HBP includes HBU
Acreage Position & Lease Expiration
Acreage Summary
Non-HBP Lease Expiration Schedule
HBP
Non-HBP
Total
2016
2017
2018
2019
2020
Total
366,633
     
186,542
     
553,175
     
Expiring Acreage
38,657
       
108,142
     
37,360
       
2,033
         
-
                 
186,192
     
66%
34%
100%
Extendable Acreage
6,056
         
24,129
       
11,168
       
-
                 
-
                 
41,352
       
182,331
     
480,471
     
662,801
     
Expiring Acreage
331,003
     
145,739
     
3,213
         
488
            
-
                 
480,444
     
28%
72%
100%
Extendable Acreage
141,947
     
78,045
       
1,060
         
90
              
-
                 
221,142
     
70,416
       
62,705
       
133,121
     
Expiring Acreage
7,385
         
46,825
       
6,580
         
1,275
         
640
            
62,706
       
53%
47%
100%
Extendable Acreage
1,040
         
-
                 
-
                 
280
            
640
            
1,960
         
18,754
       
7,693
         
26,447
       
Expiring Acreage
235
            
97
              
-
                 
7,322
         
-
                 
7,654
         
71%
29%
100%
Extendable Acreage
-
                 
8
                
-
                 
-
                 
-
                 
8
                
638,133
     
737,411
     
1,375,544
  
46%
54%
100%
CO
TX
OK
KS
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Core Assets
Mississippian

Rig Count
Utilizing full section development (FSD), extended lateral well designs, pad drilling and a focus on non-D&C spend to
increase margins within development areas
Focus Area Acreage
955k gross & 667k net acres (196k in KS, 471k in OK)
64% HBP or 426k net acres (68% in OK, 55% in KS)
2016: 85k acres expiring with extensions on ~25%, 21k @ $418/acre=$8.8MM
Current Activity
SD Focus
Area
Reduced activity and high
grading locations in response to
market conditions
Drilling 32 MidCon laterals in
2016 with a focus on Garfield
and Alfalfa Counties
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32
4
1
0
10
20
30
40
Beginning 2015
Ending 2015
Current

Mississippian Performance Overview
Mississippian Total Program Quarterly Lateral Costs
Mississippian Singles Quarterly Lateral Costs
Mississippian Single Laterals Averaged $2.1MM / Lateral in Q4 ’15
Mississippian Total Program Averaged $2.2MM / Lateral in Q4 ’15
Mississippian Single Lateral 30-Day IPs (Oil)
Mississippian Single Lateral 30-Day IPs (Gas)
Blended Type Curve
(205 BOPD)
Blended Type Curve
(1,161 MCFPD)
High Grading & Cost Reduction Efforts Result In Mississippian Outperformance
Denotes figures based on field estimates
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1,220
1,154
1,055
1,153
1,282
1,171
1,314
1,247
-
250
500
750
1,000
1,250
1,500
Q1'14
Q2'14
Q3'14
Q4'14
Q1'15
Q2'15
Q3'15
Q4'15
218
241
201
190
205
219
228
221
-
50
100
150
200
250
300
Q1'14
Q2'14
Q3'14
Q4'14
Q1'15
Q2'15
Q3'15
Q4'15
$3.3
$3.1
$3.1
$3.2
$3.4
$3.2
$3.4
$3.4
$2.7
$2.1
$2.4
$2.2
$0.0 MM
$1.0 MM
$2.0 MM
$3.0 MM
$4.0 MM
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2013
2013
2013
2013
2014
2014
2014
2014
2015
2015
2015
2015
$3.3
$3.1
$3.1
$3.2
$3.3
$3.1
$3.2
$3.2
$2.6
$2.0
$2.1
$2.1
$0.0 MM
$1.0 MM
$2.0 MM
$3.0 MM
$4.0 MM
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2013
2013
2013
2013
2014
2014
2014
2014
2015
2015
2015
2015

Sustainable Well Cost Reductions
Realized Savings
$410k Efficiency Gains
Rig efficiency & cycle time improvement 
Location high grading
Logistics
Completion design revision
Artificial lift design
$305k Service Costs
Drilling rig rates
Liner packer system
Stimulation
Directional drilling
ESP/Artificial lift equipment
$85k –
Multilateral Expansion
D&C Cost Reduction Key to Preserving Competitive Returns
$2.2MM per Mississippian lateral target achieved; additional $100,000 to be implemented in 1H 2016
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$3.6
$3.0
$2.2
-
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
$3.5
$4.0
2012
2014
Q4'15
17%
Savings
Efficiency
Gains
$410k
Service
Costs
$305k
Multilateral
Expansion
$85k
27% Savings
Realized
Mississippian Cost Savings

Latest well costs reduced from above $700 to ~$400 per completed lateral foot
Reduced Cost per Completed Foot
Cost / ft
FSDs and Extended Laterals Reduce Average Cost per Lateral
Well Name / Design
2014
Current
(1) Comprised of eight laterals and reflects Q4 2015 laterals drilled and on production
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$0
$100
$200
$300
$400
$500
$600
$700
$800
Extended
Laterals
@
$3.8MM
Willis
2709
1-18H
-
(FSD
3.0)
Mary Lu 2407 1-20H (FSD 3.0)
Carrier
2407
1-18H
-
(FSD
3.0)
Old
Design
Average
-
(FSD
3.5)
Single @ 2.1 $MM
Single @ 3.2 $MM
(1)

Produce
Over 860k barrels of water
gathered and disposed per day
during January 2016 in the Mid-
Continent and Permian Basin
>200 SWD wells in Mid-Continent
and Permian Basin
Gather & Process
Produced water is transported to
disposal location through
SD owned pipeline system
Typically Polyethylene pipe (8” to
12” diameter) connected
to producing wells, buried under
ground
Water is treated at disposal
location
Key Stats
99%
of
water
piped
vs
trucked
Average capacity of 15,000 Bblsw/d
per well
Low pressure pumps at most
locations
Various tubing sizes based on
needed capacity
Open hole Arbuckle completion
Pressure and volume continuously
monitored
Produced water disposed in Arbuckle
for ~80 years
Frac
flowback
is 1% of total
Core gathering system is
interconnected
–
maximizing
system
flexibility
1,050 miles of installed pipelines
Functionally similar to hydrocarbon
gathering and processing system
New assets, built since 2008
SWG Gathering System
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Core Assets
North Park Basin

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North Park Basin Overview
133k net acres in Jackson County, CO (53% held by
production or held by Federal Unit)
Stacked pay potential (Niobrara A, B, C, D, E, Frontier
Sand) with over 1,300 locations identified for Niobrara D
development
Estimated 25 MMBoe proved reserves (82% oil) at
projected year end 2015 SEC prices
1.0 MBoepd of current production from 16 horizontal
wells; 13 drilling permits approved; 14 submitted
3D seismic coverage over 54 square miles
100% operated with high working interest and average
royalty burden less than 17%
Asset Overview
North Park Acreage
SandRidge
Acreage

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Note: Data sourced from IHS
Competitive North Park Production Results
North Park –
7 SandRidge
Wells are in Top 30 of Colorado Niobrara Laterals <5,200 ft.
-
100
200
300
400
500
600

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North Park Basin –
Recent Well Results
502 Boepd Average 30-Day IP on Last 9 Wells
Hebron 03-12H
First Prod: Aug 2013
30-day IP:
517 Boepd
Hebron 02-7H
(C zone test, 41% outside targeted zone)
First Prod: Oct 2013
30-day IP: 325 Boepd
Coalmont
03-13H
(Poor contact with D zone and 50% of
optimal proppant)
First Prod: Aug 2013
30-day IP: 214 Boepd
Mutual 04-30H
(100% contact with targeted D zone)
First Prod: Dec 2014
30-day IP: 646 Boepd
SandRidge
Acreage
Federal Units
3D Seismic Area
Wells Drilled
Peterson Ridge 01-20H 
First Prod:
Jan 2014
30-day IP: 359 Boepd
Grizzly 03-32H
First Prod: Sep 2014
30-day IP: 619 Boepd
Spicer 03-32H
First Prod:
Aug 2014
30-day IP: 572 Boepd
Damfino
02-06H
(95% contact with targeted D zone)
First Prod: Nov 2013
30-day IP: 729 Boepd
Surprise Unit 02-08H
(most pounds of proppant
per lat. ft)
First Prod: Jul 2015
30-day IP: 538 Boepd
200-day IP:
450 Bopd

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Prior Completed NPB Niobrara Horizontal Wells
North Park Niobrara D Chalk Horizontal Well Performance
248 MBO type curve fits data which includes wells with under-stimulated completion
Type Curve Well
Selection Criteria
>600 lbs/ft of proppant
>16 Completion Stages
0
1
10
100
1,000
10,000
0
1
10
100
1,000
10,000
0
5
10
15
20
25
30
Time (months)
Surprise 2-8H
Grizzly 03-32H
Mutual 04-30H
Under-stimulated Completion
248 MBO Type Curve
SD Planned Completion
1,500 lbs/ft of proppant
30 Completion Stages

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NPB Niobrara Horizontal Well Type Curves
North Park Niobrara D Chalk Type Curve Comparison
248 MBO type curve conservative versus wells with enhanced completion method
0
1
10
100
1,000
10,000
0
1
10
100
1,000
10,000
0
5
10
15
20
25
30
Time (months)
Surprise 2-8H
Grizzly 03-32H
Mutual 04-30H
248 MBO Type Curve
381 MBO Type Curve
Type Curve Well Selection Criteria
>1,100 lbs/ft of proppant
High percentage of lateral in target zone
>22 Completion Stages
SD Planned Completion
1,500 lbs/ft of proppant
Geo-steer for 100% in target zone
30 Completion Stages

Other Assets

SandRidge owns interests in 3 Royalty Trusts which provide cash payments to SD and public
unitholders
Royalty trusts consist of mature producing properties operated by SandRidge
No capital expenditures from SandRidge are required for the trusts’ operations
All drilling obligations for the trusts have been fulfilled as of Q1’15
SandRidge provides operating and administrative services to the trust in exchange for a fee
The three trusts are Mississippian Trust I (SDT), Mississippian Trust II (SDR), and Permian Trust (PER), of which
SandRidge owns 27%, 38%, and 25% of the outstanding units, respectively
Ownership
SDT
SDR
PER
TOTAL
SandRidge
SD Subordinated
-
12,431
-
12,431 (10%)
SD Common
7,528
6,244
13,125
26,897
(20%)
Total SD Units (000s)
7,528 (27%)
18,675 (38%)
13,125 (25%)
39,328 (30%)
Common
Public Units
20,472
(73%)
31,050 (62%)
39,375 (75%)
90,897 (70%)
Total Units Outstanding
28,000
49,725
52,500
130,225
Unit Price (1.29.2016)
$2.34
$1.78
$2.72
Market
Capitalization
$65,520
$88,511
$142,800
SD
Implied Ownership
$17,616
$33,241
$35,700
$86,557
($ in 000s)
Royalty Trusts –
SDT, SDR and PER
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Appendix

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SandRidgeEnergy.com
2016 Consolidated Hedge Position
Oil Volumes Hedged (MMBbls)
Approx. $91MM in value as of 1/29/16 Strip
1Q '16
2Q '16
3Q '16
4Q '16
2016
Volumes Hedged
Oil Swaps (MMBbls)
0.4
        
0.4
        
0.4
        
0.4
        
1.5
        
Oil 3 Way Collars (MMBbls)
0.9
        
0.9
        
0.4
        
0.4
        
2.6
        
Panhandle Basis (Bcf)
2.7
        
2.7
        
2.8
        
2.8
        
11.0
     
Hedge Avg. Prices
Oil Swaps ($/Bbl)
$88.4
$88.4
$88.4
$88.4
$88.4
Oil 3 Way Collars ($/Bbl)
Average Short Call Price
$101.4
$101.4
$99.6
$99.6
$100.9
Average Long Put Price
$90.0
$90.0
$90.0
$90.0
$90.0
Average Short Put Price
$83.4
$83.4
$82.5
$82.5
$83.1
Panhandle Basis ($/Mmbtu)
($0.4)
($0.4)
($0.4)
($0.4)
($0.4)
Hedge Value ($MM)
Oil Swaps
$20.4
$18.8
$17.9
$17.3
$74.4
Oil 3 Way Collars
$6.0
$6.0
$2.8
$2.8
$17.5
Panhandle Basis Swaps
($0.5)
($0.2)
($0.3)
($0.4)
($1.4)
Total
$25.9
$24.6
$20.4
$19.6
$90.5
0.4
0.4
0.4
0.4
0.9
0.9
0.4
0.4
-
0.5
1.0
1.5
1Q '16
2Q '16
3Q '16
4Q '16
Oil Volumes Hedged (MMBbls)
Oil Swaps
Oil 3 Way Collars
1.3
1.3
0.7
0.7
2.73
2.73
2.76
2.76
2.71
2.73
2.75
2.77
1Q '16
2Q '16
3Q '16
4Q '16
Panhandle Basis Volumes Hedged (Bcf)
$20
$19
$18
$17
$6
$6
$3
$3
$0
$10
$20
$30
$40
1Q '16
2Q '16
3Q '16
4Q '16
Forecasted Hedge Value ($MM)
Oil Swaps
Oil 3 Way Collars
Panhandle Basis Swaps
$26
$25
$20
$20

30
SandRidgeEnergy.com
Summary Glossary
Glossary of
Select Terms and Acronyms
1P
–
proven reserves (proved developed
reserves and proved undeveloped reserves)
ESP
–
electric submersible pump
OOIP
–
original oil in place
2P
–
equal to 1P plus probable reserves
EUR
–
estimated ultimate recovery
PUDs
–
proved undeveloped reserves
3P
–
equal to 2P plus possible reserves
FSD
–
full section development
PV-10
–
PV of estimated future O&G
revenues, net of estimated direct expenses,
discounted at 10% annual
BO
–
barrel of oil
HBP
–
held by production
PVI
–
Present Value Index based on cash
flows discounted at 10%
BOP
–
Blowout Preventer
HBU
–
held
by unit
RR
–
rig release
BTU
–
British thermal units
HCPV
–
hydrocarbon pore volume
SD
–
SandRidge
Bblsw/d
–
barrels of water per day
IP –
initial production
STACK
–
Sooner Trend, Anadarko, Canadian,
Kingfisher (Counties)
CBP
–
Central Basin Platform
(Permian)
LOE
–
lease operating expenses
STAG
–
Sooner Trend, Anadarko, Garfield
(Counties)
CF
–
cubic feet
NMA
–
net
mineral acres
SWG
–
saltwater gathering system
D&C
–
drilling and completion
OCC
–
Oklahoma Corporation Commission
WTI –
West Texas Intermediate
Note: With respect to units of measurement (e.g., BO, BTU, CF), the following conventions apply:
Prefix M or MM = one thousand (M), one million (MM)
Suffix E =
equivalent
Suffix PD (or /d) =
per day

January 29, 2016 Strip
Q1 ’16
Q2 ’16
Q3 ’16
Q4 ’16
2017
2018
2019
2020
WTI ($ / bbl)
$32.05
$36.69
$39.70
$41.29
$43.79
$46.30
$48.00
$49.32
Henry
Hub
($ / Mmbtu)
$2.29
$2.37
$2.46
$2.61
$2.75
$2.88
$2.99
$3.11
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
Jan-16
Jul-16
Jan-17
Jul-17
Jan-18
Jul-18
Jan-19
Jul-19
Jan-20
Jul-20
WTI ($ / bbl)
Henry Hub ($ / MMbtu)
31
SandRidgeEnergy.com

SandRidge Energy, Inc.
Business Plan Overview
May 2016

33
SandRidgeEnergy.com
Disclaimer
This
presentation
regarding
SandRidge
Energy,
Inc.
and
its
subsidiaries
(“SD”
or
the
“Company”)
has
been
prepared
solely
for
informational
purposes
using
certain
Company
information
and
publicly
available
information.
Neither
the
Company
nor
any
of
its
advisors
or
representatives
makes
any
representation
or
warranty,
express
or
implied,
as
to
the
accuracy
or
completeness
of
the
information
in
this
presentation,
and
nothing
contained
herein
is,
or
should
be
relied
on
as,
a
promise
or
representation,
whether
as
to
the
past
or
the
future.
The
presentation
includes
certain
statements,
estimates,
and
projections
with
respect
to,
among
other
things,
the
anticipated
operating
performance
of
the
Company,
which
are
inherently
subject
to
significant
economic,
competitive,
and
other
uncertainties
and
contingencies
and
have
been
included
solely
for
illustrative
purposes.
This
presentation
speaks
as
of
the
date
on
which
it
is
made.
Neither
the
delivery
of
this
presentation
nor
any
further
discussions
with
the
Company
or
any
of
its
advisors
or
representatives
shall,
under
any
circumstances,
create
any
implication
that
there
has
been
no
change
in
the
affairs
of
the
Company
since
that
date.
Neither
the
Company
nor
any
of
its
advisors
or
representatives
undertakes
any
duty
to
update
or
to
correct
this
presentation.
This
presentation
is
not
intended
to
furnish
regulatory,
tax,
accounting,
investment,
restructuring,
or
any
other
advice
to
any
recipient.
This
presentation
has
been
prepared
without
taking
into
account
individual
investment
objectives,
financial
situation,
or
needs
of
any
particular
person.
The
statements
and
information
contained
in
this
presentation
that
are
not
statements
of
historical
fact,
including
any
estimates
and
assumptions
contained
herein,
are
"forward
looking
statements"
as
defined
in
Section
27A
of
the
Securities
Act
of
1933,
as
amended,
and
Section
21E
of
the
Securities
Exchange
Act
of
1934,
as
amended.
These
statements
are
qualified
in
their
entirety
by
the
"Risk
Factors,"
"Management's
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations,"
and
all
other
applicable
sections
of
the
Company's
2014
annual
report
on
Form
10-K
filed
with
the
Securities
and
Exchange
Commission
and
subsequently
filed
quarterly
reports
on
Form
10-Q.

(1)
D&C costs exclude infrastructure costs associated with tie-in of wells
Key Assumptions
34
SandRidgeEnergy.com
2016
2017
2018
2019
2020
Rigs / Laterals
1.3
Rigs
/
32
Lat.
1.5
Rigs
/
36
Lat.
2
Rigs
/
48
Lat.
2
Rigs
/
48
Lat.
2
Rigs
/
48
Lat.
Type Curve
Miss
6 type
curves
ranging
from
286
–
485
Mboe
EUR
/
257
–
446
boepd
IP-30
Chester
219 Mboe EUR /
294
boepd IP-30
D&C Costs
($ / lat)
(1)
Miss
$2.10MM
$2.00MM
$1.95MM
$1.90MM
$1.85MM
Chester
$2.85MM
$2.71MM
$2.64MM
$2.57MM
$2.51MM
LOE ($ / boe)
(Excludes
CBP)
$8.44 / boe
$9.40 / boe
$9.90 / boe
$10.30 / boe
$10.59 / boe
Rigs / Laterals
1 Rigs / 22 Lat.
1.5 Rigs / 42 Lat.
3.5 Rigs / 95 Lat.
5.5 Rigs / 146 Lat.
6.0 Rigs / 157 Lat.
Oil Type
Curve
248 Mbo EUR /
457 bopd IP-120
D&C Costs
($ / lateral)
(1)
$3.76MM
$3.60MM
$3.55MM
$3.50MM
$3.45MM
LOE ($ / boe)
$6.04
/ boe
$4.00 / boe
$4.00 / boe
$4.00 / boe
$4.00 / boe

(1)
Represents
run-rate
expense
G&A;
actual
2016
G&A
includes
~$15MM
of
severance
and
other
non-recurring
costs
including
Jan
and
Feb
payroll
prior
to
RIF
(2)
Includes
workovers,
capitalized
G&A,
midstream
&
infrastructure,
general
corporate
and
other
capex
items
not
associated
with
drilling
and
completion;
excludes
capitalized interest
(3)
Gas differential represents a percent discount to Henry Hub
(4)
Pipeline is expected to come online mid-2019
Key Assumptions (cont’d)
2016
2017
2018
2019
2020
G&A
$100MM
(1)
$80MM
$80MM
$80MM
$80MM
Non-D&C
Capex
(2)
$136MM
$105MM
$95MM
$107MM
$100MM
Price Deck
(5/3/16 Strip)
Oil
$41.11
$47.29
$48.79
$50.26
$51.66
Gas
$2.32
$2.98
$3.02
$3.03
$3.11
MidCon
(Anadarko
/ CBP)
WTI
($3.67) /
($4.00)
($3.68) /
($4.00)
($3.66) /
($4.00)
($3.65) /
($4.00)
($3.64) /
($4.00)
Henry
Hub
($0.23) /
($0.83)
($0.25) /
($0.66)
($0.30) /
($0.66)
($0.24) /
($0.67)
($0.21) / ($0.68)
NPB
(3)
WTI
($8.64)
($8.64)
($8.64)
($7.35)
(4)
($6.34)
Henry
Hub
NA
(66%)
(66%)
(66%)
(66%)
35
SandRidgeEnergy.com

2016
2017
2018
2019
2020
Q1
Q2
Q3
Q4
FY
Q1
Q2
Q3
Q4
FY
FY
FY
FY
Oil Production (MMBbls)
1.8
1.7
1.6
1.6
6.6
1.5
1.6
1.6
1.7
6.5
9.0
13.3
17.1
NGL Production (MMBbls)
1.1
0.9
0.9
0.8
3.7
0.8
0.8
0.8
0.8
3.2
3.5
3.8
4.2
Gas Production (Bcf)
17.4
15.3
14.4
13.4
60.6
13.0
12.7
12.5
12.7
51.0
50.4
51.5
53.0
Total Production (MMBoe)
5.8
5.2
4.9
4.6
20.4
4.5
4.5
4.5
4.6
18.1
20.9
25.7
30.2
% Liquids
49.6%
50.3%
50.8%
51.6%
50.5%
51.9%
52.8%
53.5%
54.6%
53.2%
59.8%
66.6%
70.7%
Daily Production (Mboepd)
63.2
56.6
53.0
50.3
55.7
50.1
49.4
48.8
50.5
49.7
57.2
70.4
82.5
Total Revenue
$122
$131
$129
$131
$513
$117
$114
$115
$121
$467
$571
$774
$983
Less: LOE
(50)
(47)
(46)
(46)
(190)
(42)
(42)
(42)
(42)
(169)
(176)
(196)
(215)
Less: Production Taxes
(2)
(3)
(3)
(3)
(12)
(3)
(4)
(4)
(4)
(15)
(24)
(37)
(46)
Less: Midstream & Marketing
(5)
(6)
(6)
(6)
(21)
(6)
(6)
(6)
(6)
(22)
(22)
(22)
(22)
Less: G&A (1)
(28)
(23)
(23)
(23)
(99)
(19)
(19)
(19)
(19)
(78)
(79)
(80)
(80)
Less: Other
(9)
(9)
(10)
(10)
(38)
(10)
(10)
(10)
(10)
(39)
(36)
(34)
(31)
Adjusted EBITDA
$28
$42
$41
$43
$153
$36
$33
$34
$40
$144
$234
$406
$589
Less: MidCon D&C Capex
(31)
(20)
(11)
(11)
(73)
(9)
(8)
(15)
(22)
(54)
(75)
(73)
(71)
Less: Rockies D&C Capex
(10)
(23)
(21)
(22)
(75)
(25)
(28)
(34)
(51)
(139)
(310)
(490)
(538)
Less: Non-D&C Capex (2)
(36)
(35)
(33)
(31)
(136)
(26)
(26)
(27)
(27)
(105)
(95)
(107)
(100)
Working Capital and Other (3)
(54)
(17)
(4)
(4)
(80)
(11)
(5)
(5)
(5)
(26)
(21)
(17)
(11)
Unlevered Cash Flow
($102)
($54)
($28)
($26)
($211)
($35)
($34)
($47)
($65)
($180)
($266)
($281)
($131)
(1)
G&A excludes non-recurring items and long term incentive plan which is anticipated to be paid in cash in 2016
(2)
Excludes capitalized interest
(3)
Includes (i) Working Capital, (ii) Non-recurring G&A and severance, (iii) cash P&A cost, (iv) retained WTO minimum volume fees not included in EBITDA, (v) non-cash G&A
included in EBITDA and (vi) Other
Total Company Business Plan Projections
Total Company 5 Year Forecast
36
SandRidgeEnergy.com

2016
2017
2018
2019
2020
Q1
Q2
Q3
Q4
FY
Q1
Q2
Q3
Q4
FY
FY
FY
FY
Total Oil Production (MBbls/d)
19.1
16.6
14.8
13.5
16.0
12.7
12.1
11.5
11.2
11.9
10.8
10.1
9.6
Total NGL Production (MBbls/d)
11.7
10.3
9.6
8.9
10.1
8.9
8.6
8.3
8.1
8.5
7.9
7.5
7.3
Total Gas Production (MMcf/d)
191.3
168.7
156.3
145.9
165.5
144.7
139.9
134.9
132.2
137.9
127.6
121.4
117.1
Total Daily Production (MBoepd)
62.6
55.1
50.5
46.8
53.7
45.7
44.0
42.3
41.4
43.3
39.9
37.9
36.4
% Liquids
49.1%
49.0%
48.4%
48.0%
48.6%
47.3%
47.0%
46.8%
46.7%
47.0%
46.7%
46.6%
46.4%
Total Revenue
$86
$96
$94
$93
$369
$94
$87
$85
$86
$353
$331
$321
$319
Less: LOE
(49)
(46)
(45)
(44)
(185)
(40)
(39)
(39)
(38)
(156)
(151)
(149)
(147)
Less: Production / Severance Taxes
(2)
(3)
(3)
(3)
(11)
(3)
(3)
(3)
(3)
(12)
(15)
(20)
(20)
Less: Other
(6)
(9)
(10)
(10)
(35)
(10)
(10)
(10)
(10)
(39)
(36)
(34)
(31)
Field-Level EBITDA
$29
$37
$37
$36
$139
$41
$36
$34
$35
$146
$128
$119
$120
Rigs
2.0
1.0
1.0
1.0
1.3
1.0
1.0
2.0
2.0
1.5
2.0
2.0
2.0
Laterals Drilled
12.0
7.0
6.0
7.0
32.0
6.0
6.0
12.0
12.0
36.0
48.0
48.0
48.0
LOE / BOE (excl CBP)
$7.91
$8.25
$8.62
$9.17
$8.44
$9.24
$9.27
$9.49
$9.63
$9.40
$9.90
$10.30
$10.59
MidCon Business Plan Projections
MidCon 5 Year Projection
37
SandRidgeEnergy.com

2016
2017
2018
2019
2020
Q1
Q2
Q3
Q4
FY
Q1
Q2
Q3
Q4
FY
FY
FY
FY
Total Oil Production (MBbls/d)
0.6
1.5
2.5
3.5
2.0
4.4
5.3
6.1
7.4
5.8
13.9
26.2
37.1
Total NGL Production (MBbls/d)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.2
0.9
0.3
1.6
3.0
4.3
Total Gas Production (MMcf/d)
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.5
5.5
1.8
10.4
19.6
27.8
Daily Production (MBoepd)
0.6
1.5
2.5
3.5
2.0
4.4
5.3
6.6
9.1
6.4
17.2
32.5
46.0
% Liquids
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
96.3%
89.9%
95.4%
89.9%
89.9%
89.9%
Total Revenue
$1
$5
$8
$12
$26
$15
$19
$22
$27
$83
$210
$423
$634
Less: LOE
(1)
(1)
(1)
(2)
(5)
(2)
(3)
(3)
(3)
(12)
(25)
(47)
(67)
Less: Production / Severance Taxes
(0)
(0)
(0)
(0)
(1)
(1)
(1)
(1)
(1)
(3)
(8)
(17)
(25)
Field-Level EBITDA
$0
$3
$7
$10
$20
$12
$15
$18
$23
$67
$177
$359
$541
Rigs
1.0
1.0
1.0
1.0
1.0
1.0
1.0
2.0
2.0
1.5
3.5
5.5
6.0
Laterals Drilled
4.0
5.0
7.0
6.0
22.0
8.0
7.0
13.0
14.0
42.0
95.0
146.0
157.0
LOE / BOE Production
$14.99
$7.57
$5.05
$4.51
$6.04
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
Rockies Business Plan Projections
Rockies 5 Year Projection
38
SandRidgeEnergy.com

Beginning 3P
Drilling Program
Ending 3P
Type Curve
Inventory (1)
2016
2017
2018
2019
2020
Inventory (1)
Orange
207
11
15
20
20
20
121
Blue
491
12
7
8
8
8
448
Green
134
2
3
4
4
4
117
Dark Orange
65
-
1
2
2
2
58
Cyan
140
-
1
2
2
2
133
Brown
774
-
1
2
2
2
767
Subtotal Miss
1,811
25
28
38
38
38
1,644
% Total
73.6%
78.1%
77.8%
79.2%
79.2%
79.2%
73.1%
Chester
545
7
8
10
10
10
500
Woodford
104
-
-
-
-
-
104
Arkoma
NA
-
-
-
-
-
NA
Subtotal
649
7
8
10
10
10
604
% Total
26.4%
21.9%
22.2%
20.8%
20.8%
20.8%
26.9%
Grand Total
2,460
32
36
48
48
48
2,248
MidCon Inventory and Drilling Schedule
MidCon 3P Inventory
(1)
3P inventory is unrisked
39
SandRidgeEnergy.com

(1)
Reflects well-head production unadjusted for shrinkage
(2)
Assumes $2.1MM/lateral cost for Miss type curves, $2.2MM/lateral for Chester type curve, and 1/29/2016 strip pricing
MidCon Type Curve Assumptions (cont’d)
MidCon
Type Curves and Well-Head Economics
(1)
3P
IP-30
EUR
IRR
Inventory
(boepd)
(Mboe)
% Oil
(2)
Orange / Dark Orange
207
446
476
25%
27%
Cyan
140
295
486
18%
18%
Green
134
308
420
25%
15%
Blue
491
384
327
24%
10%
Brown
774
257
287
24%
6%
Chester
545
294
236
58%
11%
0.0
50.0
100.0
150.0
200.0
250.0
300.0
350.0
400.0
450.0
500.0
40
SandRidgeEnergy.com

$4.7
$5.2
$4.2
$3.8
$2.2
$2.4
$2.0
$1.8
$4.0
$2.5
$5.0
$2.5
$5.0
$10.0
$10.0
$18.6
$7.6
$21.2
$18.1
-
$5.0
$10.0
$15.0
$20.0
$25.0
2017
2018
2019
2020
Flowline
Power Line
Substation
Communications
SWD
Central Tank Battery
North Park Facilities Capex
2017 –
2020 Facilities Capital Expenditures ($MM)
41
SandRidgeEnergy.com

Non-D&C Capex
Detail
Non-D&C Capex
Forecast Detail
Set forth below is the detailed break out of all non-D&C capital expenditures in the forecast
Note: Excludes capitalized interest
42
SandRidgeEnergy.com
$53
$39
$33
$28
$25
$24
$24
$26
$28
$31
$36
$24
$15
$29
$26
$16
$13
$16
$16
$13
$5
$5
$5
$5
$6
$134
$105
$95
$107
$100
-
$20
$40
$60
$80
$100
$120
$140
$160
2016
2017
2018
2019
2020
Workovers
/ Recompletions
Capitalized G&A
Midstream & Infrastructure
Leasehold, Seismic, G&G
General Corporate and Other

SandRidge Energy, Inc.
3P PV-10 Detail

Reserve
Category
PV-10
($ thousands)
Developed
$  990,230
Undeveloped
97,895
                  
Miss Proved
$  1,088,125
Technical PUDs
87,215
                  
Miss Proved + TPUDs
$  1,175,340
Developed
$  33,370
Undeveloped
-
                         
Chester Proved
$  33,370
Technical PUDs
603
                       
Chester Proved + TPUDs
$  33,973
Developed
$  14,636
Undeveloped
(20,460)
                
NPB Proved
$  (5,824)
Technical PUDs
51,808
                  
NPB Proved + TPUDs
$  45,984
Total Proved
$  1,115,671
Total Proved Incl. Technical PUDs
$  1,255,297
Developed
$  9,938
Undeveloped
-
                         
Woodford Proved
$  9,938
Technical PUDs
257
                       
Woodford Proved + TPUDs
$  10,195
Developed
$  (20,461)
Undeveloped
-
                         
Permian Proved
$  (20,461)
Total Proved
$  1,105,148
Total Proved Incl. Technical PUDs
$  1,245,031
Total Probables
$  882,954
Total 2P
$  2,127,985
Total Company Possible
$  81,419
Total 3P
$  2,209,404
Mississippian
Chester
North Park
Woodford &
Meramec
Permian
3P PV-10 Detail (1/29/16 Strip)
Note: Based on YE 2015 Reserves with
1/1/2016 Effective Date, Excluding NCI
of Royalty Trusts
44
SandRidgeEnergy.com

Reserve
Category
PV-10
($ thousands)
Developed
$  1,099,474
Undeveloped
122,517
               
Miss Proved
$  1,221,991
Technical PUDs
116,308
               
Miss Proved + TPUDs
$  1,338,299
Developed
$  38,265
Undeveloped
-
                         
Chester Proved
$  38,265
Technical PUDs
976
                       
Chester Proved + TPUDs
$  39,242
Developed
$  17,712
Undeveloped
33,099
                  
NPB Proved
$  50,811
Technical PUDs
112,114
               
NPB Proved + TPUDs
$  162,925
Total Proved
$  1,311,067
Total Proved Incl. Technical PUDs
$  1,540,466
Developed
$  11,474
Undeveloped
-
                         
Woodford Proved
$  11,474
Technical PUDs
429
                       
Woodford Proved + TPUDs
$  11,903
Developed
$  (10,336)
Undeveloped
-
                         
Permian Proved
$  (10,336)
Total Proved
$  1,312,205
Total Proved Incl. Technical PUDs
$  1,542,033
Total Probables
$  1,373,555
Total 2P
$  2,915,588
Total Company Possible
$  179,978
Total 3P
$  3,095,565
Mississippian
Chester
North Park
Woodford &
Meramec
Permian
3P PV-10 Detail (5/11/16 Strip)
Note: Based on YE 2015 Reserves with
1/1/2016 Effective Date, Excluding NCI
of Royalty Trusts
45
SandRidgeEnergy.com

April 2016
North Park Basin Update

Disclaimer
This
presentation
regarding
SandRidge
Energy,
Inc.
and
its
subsidiaries
(“SD”
or
the
“Company”)
has
been
prepared
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informational
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using
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Company
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publicly
available
information.
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Company
nor
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advisors
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makes
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warranty,
express
or
implied,
as
to
the
accuracy
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the
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in
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presentation,
and
nothing
contained
herein
is,
or
should
be
relied
on
as,
a
promise
or
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whether
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to
the
past
or
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The
presentation
includes
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with
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among
other
things,
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operating
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Neither
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undertakes
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update
or
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this
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This
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or
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other
advice
to
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This
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without
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individual
investment
objectives,
financial
situation,
or
needs
of
any
particular
person.
The
statements
and
information
contained
in
this
presentation
that
are
not
statements
of
historical
fact,
including
any
estimates
and
assumptions
contained
herein,
are
"forward
looking
statements"
as
defined
in
Section
27A
of
the
Securities
Act
of
1933,
as
amended,
and
Section
21E
of
the
Securities
Exchange
Act
of
1934,
as
amended.
These
statements
are
qualified
in
their
entirety
by
the
"Risk
Factors,"
"Management's
Discussion
and
Analysis
of
Financial
Condition
and
Results
of
Operations,"
and
all
other
applicable
sections
of
the
Company's
2014
annual
report
on
Form
10-K
filed
with
the
Securities
and
Exchange
Commission
and
subsequently
filed
quarterly
reports
on
Form
10-Q
47
SandRidgeEnergy.com

North Park Activity
Summary Update
1
st
Development
Well on
Production
Our initial well (Gregory) is cleaning up in its early flow back period,
but is tracking consistent with the type curve
Drilling
Update
Gregory 0780 1-9H: completed with 30+ days on production
Hebron 0780 1-18HR: drilled to TD, awaiting completion
Hebron 0780 2-18H: drilled to TD, awaiting completion
Hebron 0780 4-7H: drilled to TD, awaiting completion
Well Design &
Improvements
Early results illustrate benefits of enhanced stimulation methods and
our ability to quickly optimize design for maximum results
Eliminated use of intermediate casing (significant cost savings)
Use of oil based mud resulted in significant improvements in hole
stability, (increased drilling efficiency)
Use of reprocessed seismic data significantly improved targeting
D&C Costs
Cost reductions have been realized since our initial well, with clear
path to reduce costs per well to be realized ahead of schedule
Drilling time reduced by 50% over first three wells
48
SandRidgeEnergy.com

Gregory Daily Production
Gregory 0780 1-9H 30-Day IP
Rate of 550 Boepd
(89% oil)
49
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0
30
60
90
120
150
180
210
240
270
300
330
360
0
30
60
90
120
150
180
210
240
270
300
330
360
100
600
500
400
300
200
100
500
450
400
350
300
250
0
200
150
50
0
Mcf/d
Bbls/d
Type Curve Oil Rate
Risked  2016 Budget Type Curve
Gregory  Oil
Type Curve Gas Rate
Risked  2016 Budget Type Curve
Gregory  Gas

SANDRIDGE ENERGY INC Reports