SandRidge Energy (SD) 8-K Entry into a Material Definitive Agreement

SandRidge Energy, Inc.

Company Overview

February 2016

Exhibit 99.2

Disclaimer

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SandRidge

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Inc.

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looking

statements"

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27A

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1933,

as

amended,

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Exchange

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1934,

as

amended.

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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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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

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

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

SandRidgeEnergy.com

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