Edgar Filing: SANDRIDGE ENERGY INC

DEFA14A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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The following is a presentation by SandRidge Energy, Inc. about its operations and financial condition.

2013 Investor/Analyst Meeting

March 5, 2013

Disclaimer

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 SandRidge Energy, Inc.’s future operations, rig counts, drilling locations, corporate strategies, including our focus on developing and operating our assets in the Mississippian play, generating high rates of return from quality oil assets and improving our credit metrics, estimates of oil and natural gas production, reserve volumes and values, projected revenue, expenses, capital expenditures and other costs, earnings, capital raising activities and hedge transactions. 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, the successful integration of recent acquisitions, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, 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, 2012. 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 term “EUR” (estimated ultimate recovery) and “resources” and refer to their location and potential to provide estimates 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 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.

Regulation G Disclosure

This presentation includes certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our website at www.sandridgeenergy.com.

Kevin White

Senior Vice President, Business Development

Welcome &

Introductions

Agenda

SandRidge Overview Tom Ward

Chairman, Chief Executive Officer

2012 Review & 2013 Outlook Matt Grubb

President and Chief Operations Officer

Corporate Finance James Bennett

EVP and Chief Financial Officer

Mississippian Development David Lawler

EVP—Development & Production

Mississippian Technical Review Rodney Johnson

EVP—Corporate Reserves, A&D

Gulf of Mexico / Gulf Coast Development Gary Janik

SVP—Offshore Operations

Corporate Reserves Overview Rodney Johnson

EVP—Corporate Reserves, A&D

Tom L. Ward

Chairman, Chief Executive Officer

SandRidge

Overview

SandRidge Operating Regions

Asset Map

Oil Producing Regions

Mid-Continent

Gas Producing Regions Mississippian

Rigs Running: 32

Corporate Objectives

Continue to perform as the premier operator in the Mississippian

Invest in high return, growth projects, while maintaining adequate funding visibility

Further improve credit metrics

SandRidge Historic Progression

$400

$200

a) P.F. Q4’12 Adjusted EBITDA is adjusted for the Permian and Tertiary sales and Dynamic and Hunt acquisitions. This is a non-GAAP measure; please see our website for reconciliations. b) Leverage Ratio represents Consolidated Leverage Ratio calculated pursuant to the terms of the Senior Credit Facility c) P.F. YE 2012 Leverage is calculated as Pro Forma YE 2012 Net Debt, accounting for Permian proceeds and debt retirement, divided by P.F. YE 2012 Adjusted EBITDA, which reflects the

impact of acquisition and divestiture activity in 2012. Contains non-GAAP measures, please see our website for reconciliations

Pro Forma amounts are adjusted for the Permian divestiture and related debt retirement

Permian Divestiture Overview

Assets: All Permian assets, excluding SandRidge Permian

Trust properties and SandRidge’s retained interest in the underlying properties

Production of 22,900 Boe/d (4Q12)

Net Invested Capital of approximately $1.2 Billion(a)

Gross Proceeds: $2.6 Billion

Intended Use of Proceeds: Redeem a portion of our Senior Notes, with the remaining cash on the balance sheet to fund 2013 and 2014 development of the Mississippian

Strategic Rationale

Permian assets are in high demand and selling at attractive prices

Allows greater focus, financially and operationally, on our highly scalable, high return Mississippian play

Reduces outstanding debt levels and improves credit metrics

Reduces capital needs after the sale

a) Includes acquisitions and capital expenditures, adjusted for cash flows, divestitures, PER proceeds and retained units

b) Liquidity represents the quarter ending cash balance and revolver availability. 4Q12 P.F. liquidity includes proceeds from the Permian divestiture and $1.1B of debt retirement

c) Leverage Ratio represents Consolidated Leverage Ratio calculated pursuant to the terms of the Senior Credit Facility

9 d) 4Q12 P.F. represents Pro Forma YE12 Net Debt, adjusted for the Permian divestiture and Senior Note retirement, divided by 4Q12 Pro Forma LTM EBITDA

e) Contains non-GAAP financial measures. Reconciliations to the most comparable GAAP financial measures can found on our website

Today’s Agenda & Key Messages

mississippian Asset

Production growth engine through the drill-bit

Continue to delineate and develop Kansas acreage

Operational initiatives driving improved well performance

Higher returns through cost control

Infrastructure as a competitive and economic advantage

Updated Mississippian type curve

lf of Mexico / Gulf Coast Asset

Results exceeding initial expectations

Focus on maintaining production levels with recompletion/workover program, drilling and/or bolt-on acquisitions

Free cash generation funds development of the Mississippian asset

corporate Finance

Strongest financial position in SandRidge history

Permian divestiture proceeds fund capital plan into 2014

Multiple options to fund Mississippian development through 2015

Corporate Reserves

20% year-over-year reserve growth, 35% oil reserve growth

454% proved reserve replacement

Matt Grubb

President, Chief Operating Officer

2012 Review & 2013 Outlook

2012 Accomplishments

— 131% production growth, from 4Q11 to 4Q12

— Increased reserves in the play to 227 MMBoe, annual growth of 77%

Mississippian — Continued to delineate and derisk the play through ~400 wells drilled

— Expanded on salt water disposal and electrical infrastructure, substantially reducing LOE costs

— Reduced well costs by $500M/well, or 14%, to an estimated $3.1MM in 4Q12

— Increased production to over 30 MBoe/d through acquisitions, workover/recompletion program and

Gulf of Mexico new drilling, exceeding our initial target

— Generated free cash flow to fund development of our Mississippian asset

— Divested the vast majority of our Central Basin Platform properties for proceeds of $2.6B

Permian — Divestiture allows greater operational and financial focus on our core Mississippian asset and

pre-funds development plans

— Reduced leverage ratio to lowest level in corporate history

Financial(a)

— Available liquidity comfortably funds development plans into 2014

Pro Forma for the Permian sale and related debt retirement

Year-Over-Year Growth

Total Company Production(a) Mississippian Production(a)

120 40

106.8 35.9

100

e /d 66.3 e /d

o o

MB 60 MB 20 15.5

0 0

2012 Analyst Day 2013 Analyst Day 2012 Analyst Day 2013 Analyst Day

Reserves Adjusted EBITDA

$1,200

600 566 $1,070

500 471 $1,000

$800

Boe 400 MM $654

MM $ $600

300

200 $400

100 $200

0 $0

2012 Analyst Day 2013 Analyst Day 2012 Analyst Day 2013 Analyst Day

13 a) Representative of fourth quarter average daily production

2012 Review: Production

Total Company Production

120

106.8

103.0

100 90.2

66.5 Boe/d 60 M

1Q12 2Q12 3Q12 4Q12

(a)

Mississippian GOM / Gulf Coast Permian

40 40 40

35.9

31.0 31.7 30.7

30.2 30.7

29.4

30 28.6

30 30

25.2

22.9

MBoe/d 19.3 MBoe/d MBoe/d

20 20 20

10 10 10

2.8

0 0 0

1Q12 2Q12 3Q12 4Q12 1Q12 2Q12 3Q12 4Q12 1Q12 2Q12 3Q12 4Q12

14 a) Representative of Central Basin Platform properties

2012 Review: Proved Reserves

20% Reserve growth

37% growth, adjusted for Sales & Production

35% Oil reserve growth

62% growth, adjusted for Sales & Production

9% PV-10 growth

43% growth, adjusted for Sales & Production

454% Proved reserve replacement

$21.68/Boe Proved developed drilling F&D costs

$13.91/Boe Mid-Con proved developed drilling F&D costs

Negative revisions primarily related to SEC

pricing impact on WTO PUDs

Corporate Reserve Summary

Oil(a) Gas Reserves PV-10

(MBbls) (MMcf) (MBoe) ($M)

Year-End 2011(b)(c) 244,784 1,355,056 470,628 $6,875,872

Sales (23,556) (548) (23,647)

Production (17,962) (93,549) (33,553)

Purchases 32,153 202,995 65,986

Extensions 116,915 489,302 198,466

Revisions—Changes to Previous Estimates (18,536) 26,703 (14,085)

Revisions—Price Related (3,760) (564,917) (97,913)

Year-End 2012(b)(c) 330,040 1,415,042 565,880 $7,488,444

Permian Sale Adjustments (160,836) (228,229) (198,874) ($3,177,582)

Pro Forma Year-End 2012 169,204 1,186,813 367,006 $4,310,862

Pro Forma Commodity Mix Pro Forma Reserve Category

Oil PDP

46% PUD 46%

43%

Gas

54%

PDNP

11%

Includes NGLs

Includes approximately 38,230 MBoe and 26,350 MBoe attributable to Noncontrolling interest at December 31, 2012 and 2011, respectively

Includes PV-10 attributable to Noncontrolling interests of approximately $955 million and $935 million at December 31, 2012 and 2011, respectively

2012 Review: Capital Expenditures

Total Capital Expenditures

Well Count YTD Gross Net 2012 ($MM)

E&P—81%

Land & Seismic—9% Drilling and Completion

Oil Field Services—1% Mid-Continent 396 280 $927 Midstream & Other—9% Mid-Continent—SWD 60 44 95 Permian 717 695 497 Gulf of Mexico 151 All Other Areas 7 JV Carry (367)

Total Drilling and Completion 1,173 1,019 $1,310

Drilling and Completion Expenditures

Infrastructure, Workovers, Carryover & Non-Op 400 Capitalized G&A and Interest 50

E&P Capital Expenditures $1,760

Miss Hz—43%

Miss SWD—7% Land and Seismic 191

Permian—38%

Oil Field Services 28

Gulf of Mexico—11%

Midstream and Other 195

TOTAL $2,174

• Mississippian D&C is net of carry amounts

2013 Operational Objectives: Increasing Rates of Return

Mississippian

Improve well performance

Location selection process

Extrapolation of realized results

Well and completion design

Selective use of artificial lift

Continue to reduce drilling capex and LOE

Reduce casing expenditures

Reduce spud-to-first sales times

Multi-well pad drilling

Efficiently use infrastructure to manage water disposal and electrical operating costs

Continue to delineate Kansas acreage

Gulf of Mexico

Maintain production through recompletions, workovers and bolt-on acquisitions

Target capital expenditure levels of $200MM in order to generate free cash flow

Evaluate low risk, low cost, bolt-on acquisition opportunities

2013 Guidance: Production

Total Company Production

2012 2013 • 2013 Production Guidance updated for

Actuals February sale of Permian assets

Guidance

—Generates positive YoY growth after the

Oil (MMBbls)(a) 18.0 15.9 impact of the sale

Gas (Bcf) 93.5 110.4

Total (MMBoe) 33.6 34.3

• Mississippian production as growth

driver

Mississippian Production

2013

2012

February YoY

Actuals Guidance Growth • Updated 2013 Mississippian projections

yield improved liquids recoveries

Oil (MMBbls)(a) 4.6 8.2 78% —Ability to capture NGLs through new POP

Gas (Bcf) 33.0 55.5 68% agreement

Total (MMBoe) 10.1 17.4 72%

18 a) Includes NGLs

Mississippian: Driving Organic Production Growth

2012 Production Divestitures(a) Acquisitions(b) Pro Forma 2012 2013 Guidance 2013 Permian asset 2013 Guidance

excluding Permian divestiture

asset divestiture

19 a) Divestitures include 2012 production related to the divested Permian and Tertiary assets

b) Acquisitions include estimated 2012 production for acquired GoM properties not included in the actuals due to timing of the acquisitions

2013 Guidance: Capital Expenditures

Total Capital Expenditures

2013E

Well Count Total Gross Net ($MM)

E&P—83%

Drilling and Completion

Land & Seismic—6% 581 379 $1,230 Mid-Continent

Oil Field Services—2% 74 54 140 Mid-Continent—SWD

Midstream & Other—10% Permian 219 212 140 Gulf of Mexico / Gulf Coast 200 JV Carry (550)

Total Drilling and Completion 874 645 $1,160

Drilling and Completion Expenditures

Infrastructure, Workovers & Non-Op 230 Capitalized G&A and Interest 60

E&P Capital Expenditures $1,450

Land and Seismic 100

Miss Hz—59%

Miss SWD—12% Oil Field Services 30 Midstream and Other 170

Permian—12% Gulf of Mexico—17%

TOTAL $1,750

• Mississippian D&C is net of carry amounts

2013 / 2012 Capital Expenditure Comparison

2013 development primarily focused on Mississippian drilling activity

Permian development restricted to SandRidge Permian Trust drilling

Gulf of Mexico expenditures targeted to maintain production rates and generate free cash flow

Non-E&P activity expenditures reduced 28% year-over-year

$800 $680 $700

$600 $560 $500 $497 $414

MM $400 $ $300 $300 $200 $200 $140 $151 $100

Mississippian D&C Permian D&C Gulf of Mexico D&C Non-E&P 2012 Capex 2013 Capex

Mississippian Overview

• Net Acres: ~1,850,000

~11,000 potential drilling locations(a) 18 year drilling inventory

• Rig Count: 32(b)

Industry Leader: Over 2x nearest peer

• Production: 35.9 MBoe/d (4Q12)

Industry Leader

• Wells Drilled: 682(b)

Industry Leader: ~45% of total Miss wells

• Salt Water Disposal Wells: 116(b)

Industry Leader

SD horizontal wells

Peer horizontal wells

Industry vertical wells

22 a) Based on 4 wells per section (includes appraisal area)

b) As of February 28, 2013

Mississippian Production Guidance: 72% Growth in 2013

Production Growth

47.7

Average Quarterly Volumes

45 Average Quarterly Rig Counts

40 60

35.9 35

30.2 30

d 40

/ 25.2

MBoe 25 Rigs

20 19.3 30 30

15.5 15

12.7 20

8.5

5.4 5

3.6

0.8 1.6

0.3

0 0 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 2013E

Production from the Mississippian has increased over 18x since 3Q10

131% annual production growth

Commodity mix steady at ~45% oil(a) and ~55% natural gas

~80% of Mississippian cash flows come from oil production

SD Wells Drilled

2010 37

2011 167

2012 396

2013E 581

a) Includes NGLs

Mississippian Strategic Plan

Mississippian development supports corporate level double digit organic production growth

Continue to increase rates of return by improving the distribution of well results and control operating and capital costs, with an objective of less than $3.0MM per well

Continue to optimize salt water disposal and electrical infrastructure systems by increasing infill drilling within existing infrastructure

Continue to delineate and derisk Kansas acreage

Mississippian Type Curve Comparison

YE 2012(a) vs. November Guidance Forecast November YE 2012 w/ Atlas

YE 2012

Guidance Contract

• Year 1 delta = +4% Boe Oil (MBbls) 152 107 107

• Year 3 delta = -1% Boe NGLs (MBbls) 60

• Year 5 delta = -5% Boe Liquids (MBbls) 152 107 167

Nat Gas (MMcf) 1,688 1,387 1,214

MBoe 433 338 369

Mcf Shrink 13%

Total Shrink (w/ MMBtu) 20%

Liquids Recovery (Bbls/MMcf) 43.4

YR 1 YR 2 YR 3 YR 4 YR 5 YR 6 YR 7

• Production data for forecast update through Jan. 13, 2013

a) YE 2012 w Atlas includes NGL recovery

25 b) Volumes are before processing shrink

c) Does not include NGLs

Mississippian Generates Robust Economics

Nov’12 Guidance YE 2012

Capex ($MM) ROR (%) ROR (%)

$3.0 61% 55%

$3.1 57% 50% 90% of ROR realized at 5 Years

$3.2 53% 47% ~50 MBo

Nov’12 Guidance: 57% ROR

YE 2012: 50% ROR

Nov’12 Boe Guidance

YE 2012 Boe

Nov’12 Oil Guidance

YE 2012 Oil

• Includes YE2012 commercial assumptions

26 • YE 2012 includes Atlas contract

• $100/Bbl & $4.25/Mcf NYMEX pricing

Performance Comparison of 77 ESP Wells(a) to YE 2012 Type

ESP Acceleration Case with Equal Reserves YE 2012 With ESP(a)

• ~70% increase in ROR Capex ($MM) ROR (%) PV-10 ($MM) ROR (%) PV-10 ($MM)

$3.0 55% $2.9 95% $3.3

• ~15% increase in PV-10 $3.1 50% $2.8 86% $3.2

$3.2 47% $2.7 78% $3.1

YR 1

YR 2

YR 3

Includes only ESP wells with >90 days production. Field has 180 total ESP installations as of 2/15/2013.

Volumes are before processing shrink

Does not include NGLs

• Includes YE 2012 commercial assumptions

• Includes Atlas contract

27 • $100/Bbl & $4.25/Mcf NYMEX pricing

• ESP includes +$200 M/well capex and associated LOE

2013: DRILLING WITHIN INFRASTRUCTURE

2013: Drilling within Infrastructure

Focus SWD SWD Electrical

Area Wells Pipeline (mi.) Lines (mi.)

20 Alfalfa, OK 44 215 149

Comanche, KS 7 57 58

Grant, OK 15 114 97

Harper, KS 14 56 42

SW Kansas 3 14 0

25 Woods, OK 8 44 31

New Percent-of-Proceeds (POP) Agreement

SandRidge entered into a new POP agreement with Atlas Pipeline Partners, L.P.

Allows for capture of NGL volumes and enhances economics

Greater share of processing value

Lower fees

Applies to a majority of SandRidge’s Mississippian wells in Oklahoma and Southern

Kansas drilled after January 1st, 2013

Legacy production converts to new agreement in mid-2014

Gulf of Mexico / Gulf Coast Overview

Strategic Plan

• Maintain or moderately grow

production through low-risk 2012 GOM/GC PV-10 Value Growth $1,467

recompletions, workovers, drilling 2012 GOM/GC Net Investment(a) 1,257

activity and/or acquisitions

Investment Growth $210

2012 Growth over Net Investment 17%

• Evaluate low risk, low cost, bolt-on

acquisition opportunities

• Target a capital expenditure budget of

~$200MM, including acquisitions,

allowing continuation of free cash flow

generation

• Effectively manage plugging and

abandonment liabilities

a) Based on Dynamic and Hunt acquisitions, adjusted for Capital Expenditures, Plugging and

30 Abandonment and Cash Flows from Operations

Gulf of Mexico / Gulf Coast Review & Outlook

2013 Outlook: Production

~28,000 Boe/d

- Includes hurricane and operational risking

2013 Outlook: Capital Spending

2013 Guidance: $200MM

$150MM Drilling

$30MM Recompletion

$18MM Facilities

$3MM Land

James Bennett

Executive Vice President, Chief Financial Officer

Corporate

Finance

2012 Accomplishments

Surpassed consensus estimates(a):

EPS in each of the last 4 quarters

EBITDA and production in 3 of the last 4 quarters

Achieved record Adjusted EBITDA of $1,070MM ($748MM Pro Forma for acquisition and divestitures)

Fully funded capital plan

Raised ~$1.1B in 2012 through Repsol joint venture, asset sales, IPO of SandRidge Mississippian Trust II and secondary royalty trust unit offerings

Raised over $6B of capital in the past two years

• Protected cash flows via $90MM in realized hedge gains

Adjusted EBITDA ($MM) Adjusted EPS Cash Flow per Share Cash Operating Margins(b)

$1,200 $0.25 $2.00 $40

$0.23

$1,070 $34.77

$ 1.68 $35

$1,000

$0.20

$1.50 $30 $28.10

$800

$25

$654 $0.15 $ 1.09

$600 $1.00 Boe $20

$0.10

$15

$400

$0.50 $10

$0.05

$200

$ 5

$ 0.01

$0 $0.00 $0.00 $ 0

2011 2012 2011 2012 2011 2012 2011 2012

33 a) Consensus estimates sourced from Bloomberg

b) Net realized price including the impact of derivatives, net of Lease Operating Expense, Production Taxes and G&A, excluding one time items and stock based comp

2012 Accomplishments (cont’d)

Capitalization and credit measures in the best position since the Company’s founding

Greatly improved credit profile & capital structure

$1.1B year-over-year reduction in Net Debt(a)

2.3 turn reduction in Leverage ratio, year-over-year(a)(b)

No near-term maturities

Ended 2012 with over $2.4B(a) of liquidity

Pre-funded 2013 and 2014 Capital Plan with Permian proceeds

a) Pro Forma for proceeds from the Permian Divestiture, after debt reduction

34 b) Leverage Ratio represents Consolidated Leverage Ratio calculated pursuant to the terms of the Senior Credit Facility. P.F. YE 2012 Leverage is calculated as Pro Forma YE 2012 Net Debt, accounting for Permian proceeds and debt

retirement, divided by P.F YE 2012 Adjusted EBITDA, which reflected the impact of acquisition and divestiture activity in 2012

2013 Objectives

Focus on high return Mississippian projects

Grow production 18%(a), liquids 22%(a) and maintain our $1.75B capex budget

Reduce $1.1B of long term debt and associated interest expense

Maintain a leverage ratio ~3.0x

Evaluate additional sources of capital and fund the business through 2015

Salt water disposal system monetization

Kansas Mississippian Joint Venture

Royalty Trust unit sales

Continue to protect returns and cash flows via hedging

35 a) Adjusted for acquisition and divestiture activity

2013 Capital Funding Plan

$3,000

$2,500 $745

$1.1B

Funding Surplus

$2,000

$1,750

M $1,500 $ $1,415

$1,000 $858

($280)

($56)

($120) $310 $500 $403

Adjusted Interest Pref P&A Adj. CFFO YE2012 Cash Net Permian(a) Undrawn Capex

EBITDA Dividends Balance Proceeds Credit Facility(b)

Adjusted for debt retirement and deal related fees b) Adjusted for letters of credit

Adjusted for letters of credit

Credit Metrics and Liquidity

Pro Forma LTM Adjusted EBITDA(a)(d) Net Debt & Leverage(b)(d)

$1,250 $1,130 $1,183 $3,991

7.0x $4,000 $1,000 6.0x $2,903 $2,888 $3,128 $748 $3,000 $2,757 $733 $2,606 5.0x

M $750 $613 $629

M $593 M $ M 4.6x 4.0x $ $2,000 4.3x $500 4.1x $1,469

3.8x

3.0x

3.4x $1,000 2.9x $250

2.0x

$0 $0 1.0x

2Q10 4Q10 2Q11 4Q11 2Q12 4Q12 4Q12 P.F. 2Q10 4Q10 2Q11 4Q11 2Q12 4Q12 4Q12 P.F. Net Debt Leverage Ratio

Net Debt / Total Cap(d) Liquidity(c)

104% $2,500 $2,470 100%

$2,000

75%

65%

62% $1,500 $1,393

49% M

49% $ $1,055 50% 39% $1,000 $969 $641 $575 $479 21% $500

25%

0% $0

2Q10 4Q10 2Q11 4Q11 2Q12 4Q12 4Q12 P.F. 2Q10 4Q10 2Q11 4Q11 2Q12 4Q12 4Q12 P.F. Undrawn Revolver Balance Cash Balance

4Q10 and 2Q11 are Pro Forma for the Arena acquisition. 4Q11 is Pro Forma for the East Texas divestiture. 2Q12 represents the annualized adjusted EBITDA for the six months ending 6/30/2012. 4Q12 is Pro Forma for the Tertiary sale and the Dynamic and Hunt acquisitions. 4Q12 P. F. is Pro Forma for the Permian and Tertiary sales and the Dynamic and Hunt acquisitions.

Leverage Ratio represents Consolidated Leverage Ratio calculated pursuant to the terms of the Senior Credit Facility. P.F. YE 2012 Leverage is calculated as Pro Forma YE 2012 Net Debt, accounting for Permian proceeds and debt retirement, divided by P.F YE 2012 Adjusted EBITDA, which reflected the impact of acquisition and divestiture activity in 2012

37 c) Liquidity represents the quarter ending cash balance and revolver availability, adjusted for letters of credit

d) Contains non-GAAP financial measures. Please see our website for reconciliations

Debt Reduction & Senior Notes Profile

A portion of proceeds from the

Permian sale will be used to retire the 2016 and 2018 Senior Notes

$89MM of annual interest savings from debt retirement

No Senior Note maturities until 2020

7.8% weighted average cost of debt

Current Debt Maturity Summary

Weighted Average Maturity: 7.7 yrs $1,200 Weighted Average Cost: 8.0% $1,175 $825 $750 $750 $800

$366 $450 $400 $775

Floating 8.0% 7.5% 8.125% 7.5%

$0 8.75%

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Senior Notes Credit Facility

Pro Forma Debt Maturity Summary

$1,175 $1,200 Weighted Average Maturity: 8.7 yrs

Weighted Average Cost: 7.8%

$825 $750 $800

$450 $400 $775

Floa

9.8 ting 8.0

75 8.75% 7.5% 8.125% 7.5%

$0 %

2013 2014 2015 2016 %2017 2018 2019 2020 2021 2022 2023

Senior Notes Credit Facility

Credit Facility Overview

Facility Size $1,750MM

Borrowing Base $775MM

Maturity March 29, 2017

Redetermination Twice per year, Spring and Fall

Security Senior Secured

Base Rate: Prime Rate + (75 – 175 bps)

Pricing

Eurodollar Rate: Libor + (175 – 275 bps)

—Consolidated Leverage Ratio – Maximum Permitted Ratio: 4.5 to 1

Financial Covenants

—Consolidate Current Ratio – Minimum Permitted Ratio: 1.0 to 1

—Lead Banks: BofA (Agent), Barclays, RBC, RBS, SunTrust Bank, Union Bank, Wells Fargo

Lenders

—No bank holds over 6.0%

Hedging Overview

Strong hedge program provides downside protection in volatile commodity markets—Target 75-85% of current year production hedged

Continue to use derivatives to ensure financial stability

Oil 1Q13 2Q13 3Q13 4Q13 2013 2014 2015

Swaps

Volumes (MMBbls) 4.53 3.44 3.36 3.34 14.67 7.51 5.08

Price ($/Bbl) $97.56 $98.84 $98.62 $98.46 $98.31 $92.43 $83.69

Three-way Collars

Volumes (MMBbls) ————— 8.21 2.92

Call Price ($/Bbl) ————— $100.00 $103.13

Put Price ($/Bbl) ————— $90.20 $90.82

Short Put Price ($/Bbl) ————— $70.00 $73.13

LLS Basis

Volumes (MMBbls) 0.27 0.27 —— 0.54 — -

Price ($/Bbl) $15.16 $12.51 —— $13.83 — -

Natural Gas

Swaps

Volumes (Bcf) —————— -

Price ($/Mcf) —————— -

Collars

Volumes (Bcf) 1.71 1.71 1.72 1.72 6.86 0.94 1.01

Call Price ($/Mcf) $6.71 $6.71 $6.71 $6.71 $6.71 $7.78 $8.55

Put Price ($/Mcf) $3.78 $3.78 $3.78 $3.78 $3.78 $4.00 $4.00

• As of 2/26/2013

40 • Hedge positions include contracts that have been novated to or the benefit of which have been conveyed to SandRidge sponsored royalty trusts

• SandRidge has 0.2 MMBbls of oil collars in 2013 at an average ceiling price of $102.50 and an average floor price of $80

David Lawler

Executive Vice President, Development & Production

Mississippian

Development

Mississippian Development in 2013: Driving Higher Rates of Return

Increasing Well Performance

Optimizing drilling program across the play based on 2012 results

Selecting the most prolific intervals within the Mississippian

Enhancing economics and flow rates with artificial lift technology

Decreasing Development and Operating Cost

Lowering D&C costs through pioneering and implementing best practices

Improving drilling speed with rotary steerable technology

Implementing pad drilling to reduce location prep and rig move costs

Customizing casing program by region

Capitalizing on strategic competitive advantages to lower operating cost:

Produced Water Disposal System

Power Distribution Network

2012: Delineation and Appraisal

Drilled 396 horizontal Mississippian wells

$1,022MM 2012 capital program

Delineated acreage across 230 miles and 15 counties

68% development, 32% appraisal

Primary focus on Upper Mississippian member

2013: Development Focused

• >90% development,

40 appraisal wells 2013 Development Number

Focus Area of Wells

Alfalfa, OK 255

Comanche, KS 74

• 80% of the planned 2013 Ford, KS 25

Grant, OK 65

wells are within SandRidge Gray, KS 20

owned infrastructure 17 Appraisal Harper, KS 49

Wells

Woods, OK 53

Total Dev. Drilling 541

Appraisal Drilling 40

• 34% increase in horizontal Total 581

well & SWD capex(a)

- $ 1,370MM in 2013 vs.

$ 1,022MM in 2012

• 47% increase in horizontal 20

drilling activity 25

Appraisal

- 581 wells in 2013 vs. 74 49 Wells

396 wells in 2012

• 73% increase in production 53

- 17.4 MMBoe in 2013 vs. Legend

10.1 MMBoe in 2012 ??SD Leasehold 65

Development focus area 255

# of 2013 Planned wells

44 a) Excludes Joint Venture carries Appraisal area 18 Appraisal Wells

Incremental Resource Potential – Stacked Horizontal Pay

Monthly Average Boe/d

0 100 200 300 400 500 600 700

Month 1 Month 2 Month 3 Month 4 Month 5 Month 6 Month 7 Lower Miss Middle Miss Upper Miss Woodford

Potential Stacked Pay Across Mississippian Leasehold

Upper, Middle, Lower Miss Targets

1	to 3 potential Miss pay zones per location

Carbonates and Chert

Woodford Target

Mapped across significant portion of SandRidge leasehold

Impactful Ownership Position and Value

~340,000 net acres in Grant & Garfield counties

~500 controlled sections

- 200 with stacked pay potential

Vertical Correlation Wells

Potential Pay Targets

Improving Capital Efficiency: Integrating Well Data to Deliver Superior Results

•	2 wells drilled in the same section 3,960’ apart Cutaway Schematic

• Initial appraisal, Well 1, traversed two porosity

intervals to test the Upper Mississippian member

• Logs indicated higher hydrocarbon saturation in the

upper porosity interval

• Well 2 targeted the upper porosity interval, 15 feet

above the lower porosity interval, with significantly

improved production results Well 2

70 Day Oil Cum (MBo) 32

• Porosity interval knowledge extrapolated to wells in 70 Day Gas Cum (MMcf) 41

adjacent sections with positive results Disc Payout (yrs)* < 1.0

Enhanced Economics: Electric Submersible Pumps vs. Gas Lifts

ESP at Inception vs. Gas Lift Example

2	wells drilled in the same section

Artificial lift employed in both wells at inception

Electric Submersible Pump (ESP) was utilized on one well and Gas Lift on the other

ESP delivered 100% more oil and 12% more gas in 150 days

Decreased payout period from 15 to 5 months

Significant increase in rate of return

Comparative Results

ESP Gas Lift

150 Day Oil Cum (MBo) 52 26

150 Day Gas Cum (MMcf) 430 384

Disc Payout (yrs) 0.4 1.25

0 19 39 59 79 99 119 139 159 0 19 39 59 79 99 119 139 159

Days Days

47 Oil (Bo/d) LHS Gas (Mcf/d) RHS Oil (Bo/d) LHS Gas (Mcf/d) RHS

Continuous Value Enhancement: ESP Conversions Opportunities

ESP Conversion Example

Gas lift employed at well inception with favorable results

After 84 days, ESP is installed, resulting in significantly improved flow rates and economics:

Average oil production uplift >75%

Average gas production >60%

Payback period on ESP installation less than 1 month as a result of increased flow rates

Well Realizations & Economics

ESP Conversion

Installation Date (Day #) 84

Oil Uplift (Bbl/d) > 200

Gas Uplift (Mcf/d) > 800

Disc Payout (months) < 1

1	11 21 31 41 51 61 71 81 91

Days

48 Oil (Bo/d) LHS Gas (Mcf/d) RHS

SandRidge: Low Cost Mississippian Developer

Decreased drilling and completion costs by $500M/well (14%) from 1Q12 to 4Q12

Targeting gross well costs below $3.0MM by year-end 2013

Spud-to-spud cycle time declined 20% per well from 1Q12 to 4Q12

Best in class spud-to-first sales cycle time(a)

Based on SD non-op wells

Mississippian Completion Program

2	completion designs

Cemented liner with plug and perf completion

Open hole packers with sleeves

Fracture treatments range from 8 to 15 stages based on reservoir characteristics

Slick water frac with 4,500 BW and 75,000 lbs of 40/70 sand per stage

Gas-lift and ESP artificial lift based on reservoir characteristics

Completion cycle time reduced 27%

Optimized operational procedures and streamlined processes

Negotiated multiple favorable service contracts through 2013

Performance Initiative: Rotary Steerable Drilling Technology

Trial conducted in Q3 & Q4 of 2012

9 well program yielded a 32% reduction in days from surface casing to end of curve

Average of 3.5 days, significantly below fleet average of 5.2 days

50% reduction in days on most recent 2 wells

Rotary steerable system driving a 40% increase in rate of penetration

9 well RS average 110 fph, above the fleet average of 78 fph

35% improvement in ROP on most recent 2 wells

Eliminates trip for curve assembly

Based on trial success, rotary steerable drilling has been expanded to 7 rigs

Estimated net per well savings of ~$100M

Performance Initiative: Multi-well Pad Drilling

47 multi-well pads scheduled for 1st half 2013

45 Dual Pads

Quad Pads

Drilling 2 and 4 wells per pad improves efficiencies and reduces environmental footprint

Anticipate an average total savings of $125M / well

Savings result from:

Reduced rig moves

Consolidated location preparation

Improved completion efficiency

Facilities sharing

Performance Initiative: Region Specific Casing Design

Current Casing Design

• Identified potential to eliminate 7” intermediate casing string in

certain area of the play

• Simplified well design minimizes trips and eliminates time and

cost for running 7” intermediate casing and 4.5” production

strings

• Potential $200M savings per well in rig time and tangible costs

• First 4 wells scheduled to spud in 1Q13 Single Casing String Design

Current Casing Design Single String Design

Surface 9-5/8” @ 1,000’ 9-5/8” @ 1,000’

Intermediate 7” @ 5,500’ None

Production 4-1/2” @5,300—9,500’ 5-1/2” @ 9,500’

Salt Water Disposal System Overview

116 active disposal wells

~700 miles of pipeline

Disposal rate of ~700 gross MBW/d

Over $450MM gross invested capital

54 • Figures are as of February 2013

SWD: Secures Competitive Advantages & Maximizes Value

Produced water volumes increased over 100% in the Mississippian in 2012

Effectively managing produced water is key to controlling operating costs in the play

LOE savings of over $2.00 per produced barrel of water relative to trucking volumes

Water:Boe ratios in the Mississippian ~9.5:1

Operating cost savings over trucking result in quick recovery of initial SWD development cost

10 producing wells per SWD well: 4 month payback from savings over trucking

5	producing wells per SWD well: 8 month payback from savings over trucking

Electrical System Overview

Electrical System

Access to over 100 MW

~500 miles of power distribution lines

3	operated substations, 4 additional substations in 2013

Power available to support 400 ESPs

- Currently operating 175 ESPs

56 • Figures are as of year-end 2012

Electrical System Benefits

Sandy Corner Sub-Station

Produced water transfer and artificial lift systems require high voltage

Sourcing power solely from diesel generators presents economic and logistical challenges

SandRidge proactively constructed infrastructure to access regional transmission networks

Converting ESP wells to local power from diesel generators results in ~$100M/month per well in operating cost savings

SandRidge: Low Cost Mississippian Operator

Trucked Water Progression Percent of Wells on Generator

9% 40%

8% 8.1% 35% • Proactively managing infrastructure needs

35%

k ed 7% 30% and capitalizing on scale allows SandRidge

r 6%

T 25% to be a low cost operator in the play

Water 5%

20%

15% 13%

Produced 3%

10%

of 2%

% 0.9% 5%

1% • Trucked water volumes are less than 1.0%,

0% down from over 8.0% in early 2012

% on Diesel Generators % on NatGas Generators

Mississippian LOE Progression

$16 • Number of wells on generators have declined

$13.38 by over 20% as a result of SandRidge’s

$12 expanding electrical infrastructure

/B $8 $7.65

$4 • As a result, LOE has declined 43% from

4Q11 to 4Q12

4Q11 4Q12

Excludes Production Tax

Mississippian Value Equation

The sum of these strategic elements drives high rates of return

+ + +

+ +

- BREAK -

Rodney Johnson

Executive Vice President – Corporate Reserves, A&D

Mississippian

Technical

Overview

Mississippian Technical Highlights

DeRisked Resource Play Over 11.5 Million Acres

> 1,500 horizontal wells to date; 82 rigs running today

Expanded Play Across 230 Miles

Total potential 17 million acres; SandRidge ? 1.85 million net acres

Proven Reserve Potential Increased

4	wells/section YE 2012 vs. 3 wells/section YE 2011 Statistical reserve booking potential

Confidence in ROR Significantly Improved

644 PDP wells in YE 2012 type curve vs. 145 PDP wells in YE 2011

Mississippian – 1,535 Drilled Wells and 82 Active Rigs

based on 4 wells per section (includes appraisal area)

Drilled well counts as of 2/28/13

Mississippian Engineering Discussion

2012 Analyst Day

456 type curve (300-500 MBoe range) based on 145 PDP wells (3 wells per section)

b factor could improve in one year

Statistical booking of PUDs ~2 years off

Continuing to extend the play

Derisk play

Current Outlook

369 MBoe, 107 MBo, 167 MLiquids, 1,212 MMcf, 45% liquids

Based on 644 PDP wells

b factor for gas at 2.0

b factor for oil remained the same, but evidence would suggest could be higher

Higher initial rates with steeper declines —- need more time on data set

ROR very robust, confidence level has significantly increased

644 wells in dataset

ROR dictated by first 4-5 years

EUR range still 300-500 MBoe

Capex has been tested over hundreds of wells

Atlas contract allows NGL recovery

Continued expansion of proven area

Proven reserve booking potential increased

4	wells per section

Current methodology yields ~1:1 PDP to PUD booking

Statistical method in proof of concept stage

Mississippian Type Curve Comparison

YE 2012(a) vs. November Guidance Forecast November YE 2012 w/ Atlas

YE 2012

Guidance Contract

• Year 1 delta = +4% Boe Oil (MBbls) 152 107 107

• Year 3 delta = -1% Boe NGLs (MBbls) 60

• Year 5 delta = -5% Boe Liquids (MBbls) 152 107 167

Nat Gas (MMcf) 1,688 1,387 1,214

MBoe 433 338 369

Mcf Shrink 13%

Total Shrink (w/ MMBtu) 20%

Liquids Recovery (Bbls/MMcf) 43.4

YR 1 YR 2 YR 3 YR 4 YR 5 YR 6 YR 7

• Production data for forecast update through Jan. 13, 2013

a) YE 2012 w Atlas includes NGL recovery

65 b) Volumes are before processing shrink

c) Does not include NGLs

Mississippian Oil EUR Comparison

Oil EUR Sensitivity 1,439 Wells Vertical Wells

66 MBbls EUR

• YE 2012 Oil Type Curve = 107 MBo b Factor of 2.5

Final Decline < 5%

• Nov’12 Guidance = 152 MBo 3 County Area (Woods, Alfalfa, Grant)

• Nov’12 Guidance with 3% final = 180 MBo

Type Curve Progression

General Discussion: 300-500 MBoe

Statistical Understanding of the

Mississippian 369 MBoe

• YE 2010: 37 TC wells with history

• YE 2011: 145 TC wells with history Count

– 3.9x 2010 Well

• YE 2012: 644 TC wells with history PDP

456 MBoe

– 4.4x 2011

– 17.4x 2010

409 MBoe

235 MBoe

Mississippian Generates Robust Economics

90% of ROR realized at 5 Years

~50 MBo

Pro Forma curve established with over 640 PDP wells

ROR driven by recovery within 5 Year window

Expense and capex drivers tested over 640 wells

YE 2012

Capex ($MM) ROR (%)

$3.0 55%

$3.1 50%

$3.2 47%

• Includes YE 2012 commercial assumptions

• YE 2012 Includes Atlas contract

• $100/Bbl & $4.25/Mcf NYMEX pricing

68 • YE2012 capex $3.1 MM

Rate of Return Sensitivity

ROR Sensitivity to Capex and Commodity Pricing

Type curve variance(a) = ~ 6% ROR

Capex variance per $100M = ~5% ROR

Commodity price per $10/Bbl oil price = ~10% ROR

$80/$4.25 $90/$4.25 $100/$4.25 $110/$4.25 $120/$4.25 $80/$4.00 $90/$4.50 $100/$5.00 $110/$5.50 $120/$6.00

NYMEX Pricing (Bbl/Mcf) NYMEX Pricing (Bbl/Mcf)

a) YE 2012 compared to November guidance

• Includes YE 2012 commercial assumptions

• YE 2012 Includes Atlas contract

69 • $100/Bbl & $4.25/Mcf NYMEX pricing

Expansion of Top Performing EURs Across 230 Miles

Mississippian Acreage Value – Evaluated & Appraisal

YE 2012 EUR >P50

YE 2011 EUR >P50

Mississippian IP Distributions

Avg. 1,547 Boepd

Avg. 1,266 Boepd Avg. 614 Avg. 676 Boepd Boepd Avg. 335 Avg. 354 Boepd Boepd

Avg. 166 Avg. 175 Boepd Boepd

Average

Avg. 44 Avg. 61 30 Day Rate Wells Rigs

(Boe/d) Boepd Boepd

Rate (Boe/d)

Peak Oklahoma 356 472 24 Kansas 254 110 8

Average Total 336 582 32

Day YE 2012 Type Curve

30 1st 30 day IP = 272 Boe/d

• Includes all SandRidge operated Mississippian wells drilled through 2/18/2013 with at least 30 days of production • Rig counts are as of 2/18/2013

Kansas Mississippian Performance Comparable to Oklahoma

Kansas vs. Oklahoma

Horizontal performance = accelerated vertical cum = ROR

Comparable vertical cums to Oklahoma

Significantly lower declines

Lower IP’s

Mississippian Appraisal Area

Regional Mississippian Sub Crop Map

HODGEMAN /NESS: KEY LEARNINGS

Tested 6 wells non-commercial with high water saturations

Currently evaluating uphole potential

One Year Closer to Statistical PUD Booking Methodology

3	Wells/Sec YE 2011, 4 Wells/Sec YE 2012, Operator Testing 5 Wells/Sec

• ~42 Well sets analyzed in detail

- 114 wells on 3 wells per section spacing

- 16 wells on 4 wells per section spacing EUR ratio comparison of 61 well pairs

• No degradation to primary well performance indicates outcomes within expected statistical

variation – no obvious spacing influence

• Subsequent wells meet statistical performance

expectation

• Confirmed viability of 4 wells/section

• Where applicable booked 4 wells/section

Woods County Example: 5 wells per section

Mississippian: Detailed Performance Area Discussion

Central Finney County, Kansas – Farthest NW Expansion Area

Well Detail:

Sub Crop: St. Genevieve

Primary Lithology: Limestone

Gross Thickness: 600’

EUR: 240 MBo

30 Day Peak IP:

58 Bo/d

Mcf/d

59 Boe/d

Central Gray County, Kansas

Well Detail:

Sub Crop: St. Genevieve

Primary Lithology: Limestone

Gross Thickness: 800’

EUR: 189 MBo

30 Day Peak IP:

122 Bo/d

122 Boe/d

Southwestern Ford County, Kansas

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Dolomite

Gross Thickness: 850’

EUR: 245 MBo

30 Day Peak IP:

126 Bo/d

102 Mcf/d

143 Boe/d

Northwestern Comanche County, Kansas

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Dolomite

Gross Thickness: 750’

EUR:

109 MBo

1,140 MMcf

299 MBoe

30 Day Peak IP:

96 Bo/d

1,164 Mcf/d

290 Boe/d

Southwestern Comanche County, Kansas

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Dolomite

Gross Thickness: 700’

EUR:

60 MBo

3,170 MMcf

588 MBoe

30 Day Peak IP:

74 Bo/d

787 Mcf/d

205 Boe/d

Eastern Comanche County, Kansas

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Dolomite

Gross Thickness: 550’

EUR:

185 MBo

940 MMcf

341 MBoe

30 Day Peak IP:

219 Bo/d

678 Mcf/d

332 Boe/d

Eastern Woods County, Oklahoma

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Chert

Gross Thickness: 450’

EUR:

500 MBo

2,300 MMcf

883 MBoe

30 Day Peak IP:

102 Bo/d

895 Mcf/d

251 Boe/d

Northern Alfalfa County, Oklahoma

Well Detail:

Sub Crop:

Spurgen-Warsaw

Primary Lithology: Lime/Chert/Dolomite

Gross Thickness: 350’

EUR:

392 MBo

3,661 MMcf

1,003 MBoe

30 Day Peak IP:

551 Bo/d

3,189 Mcf/d

1,083 Boe/d

Central Alfalfa County, Oklahoma

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Lime/Dolomite/Chert

Gross Thickness: 450’

EUR:

418 MBo

2,648 MMcf

859 MBoe

30 Day Peak IP:

84 Bo/d

395 Mcf/d

150 Boe/d

Southern Alfalfa County, Oklahoma

Well Detail:

Sub Crop: St. Louis

Primary Lithology: Limestone/Chert

Gross Thickness: 600’

EUR:

172 MBo

964 MMcf

332 MBoe

30 Day Peak IP:

237 Bo/d

1,414 Mcf/d

473 Boe/d

Southern Harper County, Kansas

Well Detail:

Sub Crop:

St. Louis-Spurgen

Primary Lithology: Lime/Chert/Dolomite

Gross Thickness: 350’

EUR:

199 MBo

904 MMcf

350 MBoe

30 Day Peak IP:

674 Bo/d

682 Mcf/d

788 Boe/d

Western Grant County, Oklahoma

Well Detail:

Sub Crop:

St. Louis-St. Genevieve

Primary Lithology: Limestone/Chert

Gross Thickness: 500’

EUR:

192 MBo

1,083 MMcf

373 MBoe

30 Day Peak IP:

271 Bo/d

144 Mcf/d

295 Boe/d

Central Grant County, Oklahoma

Well Detail:

Sub Crop:

St. Louis-St. Genevieve

Primary Lithology: Limestone/Chert

Gross Thickness: 600’

EUR:

325 MBo

1,151 MMcf

517 MBoe

30 Day Peak IP:

502 Bo/d

715 Mcf/d

621 Boe/d

Northern Garfield County, Oklahoma

Well Detail:

Sub Crop:

St. Louis-St. Genevieve

Primary Lithology: Limestone/Chert

Gross Thickness: 600’

EUR:

281 MBo

2,670 MMcf

726 MBoe

30 Day Peak IP:

75 Bo/d

762 Mcf/d

202 Boe/d

Northwestern Noble County, Oklahoma

Well Detail:

Sub Crop: Osage

Primary Lithology: Chert/Limestone

Gross Thickness: 600’

EUR:

154 MBo

718 MMcf

274 MBoe

30 Day Peak IP:

396 Bo/d

577 Mcf/d

492 Boe/d

Gary Janik

Senior Vice President, Offshore Operations

Gulf of Mexico Gulf Coast Development

Gulf of Mexico / Gulf Coast Overview

Focused on low risk workover, recompletion and drilling opportunities

Shallow, offshore Gulf of Mexico and Gulf Coast properties

All wells on fixed structures

Properties from Mustang Island across the Gulf to Pensacola

Strong team with extensive experience in operations, acquisitions and abandonments

Production: 31.7 MBoe/d (4Q12)

Wells

368 Operated producing

613 Operated non-producing

High focus on safety in operations

INC to Component Ratio 20% below Industry average

GOM/GC 2012 Review

SandRidge acquired Dynamic Offshore Resources in April of 2012, adding ~25,000 Boe/d of production

Additional Gulf properties were later acquired in June, adding ~3,000 Boe/d of production

4Q12 production of 31.7 MBoe/d, highlighting success of low risk drilling, recompletion and workover programs

2012 Capital:

Drilling: $93MM

Recompletions: $77MM

Facilities: $4MM

GOM/GC Business Plan

Find value accretive, low risk acquisition opportunities

Identify low to moderate risk exploitation opportunities

Utilize current infrastructure

Primarily fixed operating costs

Incremental production volumes add little expense

Proactively conduct abandonment to save operating expenses and reduce risk

Conduct all operations safely

Strengths

Proven operator in the Gulf of Mexico

Fully staffed with qualified, experienced professionals

Ready infrastructure for rapid on-line time for completed projects

Safe operator

Acquisition Capabilities

Acquisition Strategy

Identify quality assets with motivated sellers

Selectively acquire based on conservative valuation of proved reserves

Acquire properties with low-risk upside but majority of purchase price based on known production/reserves

Consolidate interests in quality properties

Acquisition Case Study

Acquisition Metrics Production

8,000

Purchase Price ($MM) $51.0

Recompletion of

Purchase Price / Production $14,153 El 77 #9,10,11

Original Production (Boe/d) 3,600 7,000

Purchase Price / Reserves $6.23

Reserves (MMBoe) 8.2 6,000

Purchase Price / Operating Income 1.7x

Original Operating Income per Month $2.5

5,000

4,000

Acquisition Lookback Boe/d

Purchase Price ($MM) $51.0 3,000

Cash Flows (30.0)

Divestitures (7.2) 2,000

Capital Investments 1.7

1,000

Net Investment $15.5

Remaining PV-10 ($MM)(a) $55.3 0

Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13

100 a) Modified 2/4/2013 Strip (Escalated & Capped $100/Bbl and $5.00/Mcf) Unhedged

Ship Shoal 301

Drilling Program Case Study

Ship Shoal 301

- WI – 100%

- NRI – 80.98%

SS 301 #A-1 Side Track

Trim B Completion

Net Pay – 67 ft.

1,788 BO/d

1,787 Mcf/d

0 BW/d

1,650 PSI Tubing Pressure

SS 301 #A-3 Side Track

- Cris S Target Net Pay

- Upper Cris S 22 ft.

- Lower Cris S 62 ft.

- Completing – 25 days

SS 301 #A-5

Trim B Target

Next Drill location

25 days to drill, 16 to complete

101

Eugene Island 77

Recompletion Case Study Eugene Island 77 #9

Induction/GR/Sonic/Neutron/Density Log

Eugene Island 63/77 1983

- WI – 100% WW Sand

- NRI – 83.33% #9

• El 77 #9 – WW Sand

#11

- 99 BO/d

- 3,980 Mcf/d

- 4 BW/d #10

- 3,775 PSI Tubing Pressure

• El 77 #10 – T-1 Sand

- 540 BO/d

- 1,700 Mcf/d Eugene Island 77 #10 Eugene Island 77 #11ST2

PNL Log T-1 Sd PNL Log

- 876 BW/d Nov 2012 Dec 2012

• El 77 #11 – T-1 Sand

- 530 BO/d

- 14,500 Mcf/d

- 5 BW/d

- 3,800 PSI Tubing Pressure

T-1 Sand

1st Perf: 13,071’ – 084’ MD

Test to determine flow and product

2nd Perf: 13,016’ – 028’ MD

102

GOM/GC 2013 Forecast

Production Guidance

~28,000 Boe/d annual rate

- Adjusted for hurricane and operational risking

Abandonment Spending

2013 Guidance $120MM

$30MM for 170 wells

$29MM for 28 platforms

$23MM Bullwinkle payment

$38MM EB 110/165 abandonment

Normal abandonment run rate guidance: ~$65MM

103

Rodney Johnson

Executive Vice President – Corporate Reserves, A&D

Corporate

Reserves

Overview

SandRidge Summary – Year End 2012

Increase in SEC PV-10 Value 43%(a) to $7.5 Billion

Net Reserves & Resource Value(b) $28.6 Billion

Proved Reserve Replacement 454%

Increase in Proved Developed Reserve Value to 67% of Total

and Increase in Liquids Revenue to 89% of Total

Proved Developed Drilling Finding Costs $21.68/Boe

(a)	Adjusted for asset sales and production (b) Includes $1.7B NAV for KS appraisal area

105

SandRidge Summary – Year End 2012

Increase in SEC PV-10 Value 43%(a) to $7.5 Billion

Net Reserves & Resource Value(b) $28.6 Billion

Proved Reserve Replacement 454%

Increase in Proved Developed Reserve Value to 67% of Total

and Increase in Liquids Revenue to 89% of Total

Proved Developed Drilling Finding Costs $21.68/Boe

(a)	Adjusted for asset sales and production (b) Includes $1.7B NAV for KS appraisal area

105

Proved Reserve & Value Waterfall

800 SandRidge 10,000 SandRidge

MMBOE PV10 $MM

9,000

700 (1,235)

1,708

8,000

600 2,092 7,488

198 566 7,000 6,876 (410) (1,543)

66 (34)

500 471 (112)

(24)

6,000

400 5,000

300 4,000

3,000

200

2,000

100

1,000

0 0

2011 YE Divestiture Acquisition Production Revisions Extensions 2012 YE 2011 YE Divestiture Acquisition Production Revisions Extensions 2012 YE

Revisions 87% Pricing (Gas), 13% Performance 2011 YE SEC Pricing—$92.71/ $4.118

2012 YE SEC Pricing—$91.21/ $2.757

SandRidge

Total Proven

Reserve Waterfall

SEC Pricing—$91.21 / $2.757

Liquids, MBbls Gas, MMcf MBoe PV-10 ($000)

As of 12/31/2011 244,785 1,355,056 470,628 $ 6,875,872

Acquisition of reserves 32,153 202,995 65,986 1,708,301

Sales of reserves (23,556) (548) (23,647) (410,415)

Production (17,962) (93,549) (33,553) (1,234,918)

Extensions & Discoveries 116,915 489,302 198,466 2,092,423

Revisions of previous estimates (22,296) (538,214) (111,998) (1,542,819)

As of 12/31/2012 330,040 1,415,042 565,880 $ 7,488,443

106 • Includes Royalty Trust

Total Net Proved Reserves Total Net PV-10

566 MMBoe $7,488 Million

Permian Permian

236 3,981

42% 50%

107 • Includes Royalty Trust

Reserves and Value

Year End 2012 Proved Reserves

SEC Pricing— $91.21 / $2.757

Reserves by Category

Liquids Gas Equivalent PV-10

MMBbls Bcf MMBoe % Millions %

PDP—Producing 138 683 251 44% $ 3,999 53%

PBP—Behind Pipe 13 98 29 5% 307 4%

PNP—Non Producing 20 115 39 7% 742 10%

PUD—Undeveloped 160 518 246 43% 2,763 37%

PP&A—Offshore Abandonment ——— 0% (323) -4%

Total Proved 330 1,415 566 $ 7,488

Total Developed 170 897 320 57% 5,048

Total Undeveloped 160 518 246 43% 2,763

Total Offshore Abandonment ——— 0% (323) —

Total Proved 330 1,415 566 $ 7,488 Up

from 64%

Reserves by Region

Liquids Gas Equivalent PV-10

MMBbls Bcf MMBoe % Millions %

Mid-Continent 100 813 236 42% 2,318 31%

Permian 195 242 236 42% 3,981 53%

Southern 34 182 64 11% 1,409 19% Up

WTO/Other 0 178 30 5% (219) -3%

Total Proved 330 1,415 566 $ 7,488 from 26%

108 • Includes Royalty Trusts

Increasing Proven Oil Mix

Improved Oil Reserve Mix YE 2012 SEC

100%

90%

80%

42% 48%

70% 52% 54% 60% 86%

88% Improved Oil Revenue YE 2012 SEC

50%

40%

30% 58% 11%

52% 21% 48% 46%

20%

10% 14%

12%

YE ‘07 YE ‘08 YE ‘09 YE ‘10 YE ‘11 YE ‘12

89%

GAS OIL 79%

YE ‘11 YE ‘12

GAS OIL

109 • Includes Royalty Trusts

• Oil includes NGLs

SandRidge Predominately Proved Oil Well Value

110

Sec pricing

Includes Royalty Trusts

Proved F&D Costs, Reserve Life, & Replacement Ratio

2011 CAPEX $ in Millions 2012 CAPEX $ in Millions

E&P drilling & production capex $ 1,382 E&P drilling & production capex $ 1,764

Land & Seismic 348 Land & Seismic 191

Acquisitions 35 Acquisitions (a) 1,383

Total cost incurred — All-in F&D $ 1,765 Total cost incurred — All-in F&D $ 3,338

2011 Finding & Development Metrics 2012 Finding & Development Metrics

Excluding Including Excluding Including

E&P CAPEX Revisions Revisions E&P CAPEX Revisions Revisions

Extensions, MBoe 105,551 105,551 Extensions, MBoe 198,466 198,466

Revisions, MBoe — (36,751) Revisions, MBoe — (111,998)

105,551 68,800 198,466 86,468

Drilling F&D ($/Boe) $13.10 $20.09 Drilling F&D ($/Boe) $8.89 $20.40

Reserve Replacement 451% 294% Reserve Replacement 592% 258%

E&P, Land & Seismic, & Acq CAPEX E&P, Land & Seismic, & Acq CAPEX

Extensions, MBoe 105,551 105,551 Extensions, MBoe 198,466 198,466

Revisions, MBoe (36,751) Revisions, MBoe (111,998)

Acquisitions, MBoe 2,018 2,018 Acquisitions, MBoe 65,986 65,986

107,569 70,818 264,452 152,454

All-in F&D ($/Boe) $16.41 $24.92 All-in F&D ($/Boe) $12.62 $21.89

All-in Reserve Replacement 460% 303% All-in Reserve Replacement 788% 454%

Proved reserve life (years) 20.1 Proved reserve life (years) 16.9

2011 production (MBoe) 23,381 2012 production (MBoe) 33,553

a) DOR $693MM cash + $542MM equity

• SEC Pricing

111

• Includes Royalty Trusts

Proved F&D Costs, Reserve Life, & Replacement Ratio

2012 Finding & Development Metrics 2012 Proved Developed Finding Costs

Excluding Including

E&P CAPEX Revisions Revisions Reserves Related Metrics & Ratios

Extensions, MBoe 198,466 198,466 Current Period Proved Developed Reserves (MMBoe) 319.8

Revisions, MBoe — (111,998) —Prior Period (230.4)

198,466 86,468 + Production 33.6

123.0

Drilling F&D ($/Boe) $8.89 $20.40

Sales—Developed (MMBoe) 8.2

Acquisitions—Developed (MMBoe) (49.8)

Reserve Replacement 592% 258%

Organic PD Reserve Additions (MMBoe) 81.4

E&P, Land & Seismic, & Acq CAPEX

Extensions, MBoe 198,466 198,466

CAPEX (Millions)

Revisions, MBoe (111,998)

Drilling costs $ 1,764

Acquisitions, MBoe 65,986 65,986

Land & Seismic 191

264,452 152,454

Total Organic Capital $ 1,955

All-in F&D ($/Boe) $12.62 $21.89 Proved Developed Finding Costs ($/Boe)

Drilling only $21.68

With Land & Seismic $24.02

All-in Reserve Replacement 788% 454%

Proved reserve life (years) 16.9

2012 production (MBoe) 33,553

2012 CAPEX $ in Millions

E&P drilling & production capex $ 1,764

Land & Seismic 191

Acquisitions (a) 1,383

Total cost incurred — All-in F&D $ 3,338

a) DOR $693MM cash + $542MM equity

112 • SEC Pricing

• Includes Royalty Trusts

SandRidge Corporate Reserves Adjusted for PER, SDT, & SDR Trusts

NET RESERVES

OIL, NGL, LIQ, GAS, MMBoe PV-10

MMBbls MMBbls MMBbls Bcf ($MM)

Consolidated SandRidge (10K Reporting)

PDP 109 28 138 683 251 $ 3,999

PBP 9 3 13 98 29 307

PNP 18 2 20 115 39 742

PUD 125 34 160 518 246 2,763

OFFSHORE PP&A ————— (323)

TOTAL 262 68 330 1,415 566 $ 7,488

Royalty Trusts—3rd Party Ownership

PDP 10 3 14 69 25 $ 562

PBP 0 0 0 0 0 5

PNP 1 0 1 2 1 35

PUD 6 2 8 24 12 353

TOTAL 17 5 22 95 38 $ 955

SandRidge Excluding 3rd-Party Ownerhip of Royalty Trusts

PDP 99 25 124 615 226 $ 3,438

PBP 9 3 13 98 29 301

PNP 17 2 19 113 38 707

PUD 119 33 152 494 234 2,411

OFFSHORE PP&A ————— (323)

TOTAL 245 63 308 1,320 528 $ 6,534

113 • SEC Pricing

Reserve Distribution by Value and Reserves

• SEC Pricing

• Includes Royalty Trusts

114

Mid-Continent Summary

SEC PV-10 Value remains(a) at $2.3 Billion Net Reserves & Resource Value(b) $17 Billion Proved Reserve Replacement 918%

60% Proved Developed Reserve Value & 80%(c) Oil Revenue

Miss Proved Developed Drilling F&D Costs $13.91/Boe

a) Adjusted for asset sales and production

b) Includes $1.7B NAV for KS appraisal area

115 c) Oil Revenues include NGLs

Mid-Continent Summary

SEC PV-10 Value remains(a) at $2.3 Billion Net Reserves & Resource Value(b) $17 Billion Proved Reserve Replacement 918%

60% Proved Developed Reserve Value & 80%(c) Oil Revenue

Miss Proved Developed Drilling F&D Costs $13.91/Boe

a) Adjusted for asset sales and production

b) Includes $1.7B NAV for KS appraisal area

115 c) Oil Revenues include NGLs

Mid-Continent Proved Reserve & Value Waterfall

300 3,000

280

260

2,500

240 125 236 50 (420) 1,097 2,318

2,265

220

200 2,000 (675)

180

160 146 5 (11)

(28)

1,500

140

120

100 1,000

500

0 0

2011 YE Acquisition Production Revisions Extensions 2012 YE 2011 YE Acquisition Production Revisions Extensions 2012 YE

2011 YE SEC Pricing—$92.71/ $4.118

2012 YE SEC Pricing—$ 91.21/ $2.757

Mid-Continent revisions include ~10 MMBoe downward revisions from pricing

~18MMBoe performance revisions (~12%, primarily Miss)

116 • Includes Royalty Trusts

Gulf Coast & Gulf of Mexico Waterfall

Primary reserve changes: Dynamic/Hunt acquisition +60.8 MMBoe

Pricing revisions -2.7 MMBoe offset by performance revisions +2.4 MMBoe

Offshore/Southern reserves represents ~11% of total corporate (18% Pro Forma after Permian sale)

117

Pro Forma YE Reserves SandRidge Post Permian Divestiture

Year End 2012 Proved Reserves

SandRidge Less Permian Divestiture Pro Forma

SEC Pricing—$91.21/ $2.757

Reserves by Category Equivalent MMBoe PV-10 Millions

Permian Permian

YE2012 Pro Forma YE2012 Pro Forma

Divest % Divest %

PDP—Producing 251 84 167 46% $3,999 $1,685 $2,315 54%

PBP—Behind Pipe 29 17 12 3% 307 275 32 1%

PNP—Non Producing 39 9 30 8% 742 80 662 15%

PUD—Undeveloped 246 89 158 43% 2,763 1,138 1,625 38%

PP&A—Offshore Abandonment ———— -323 — -323 -

Total Proved 566 199 367 -35% $7,488 $3,178 $4,311 -42%

Total Developed 320 110 210 57% 5,048 2,040 3,009 70%

Total Undeveloped 246 89 158 43% 2,763 1,138 1,625 38%

Total Offshore Abandonment ———— -323 0 -323 -7%

Total Proved 566 199 367 -35% $7,488 $3,178 $4,311 -42%

Reserves by Region

Permian Permian

YE2012 Pro Forma YE2012 Pro Forma

Divest % Divest %

Mid-Continent 236 — 236 64% $2,318 — $2,318 54%

Permian 236 199 37 10% 3,981 3,178 803 19%

Southern 64 — 64 18% 1,409 — 1,409 33%

WTO/Other 30 — 30 8% -219 — -219 -5%

Total Proved 566 199 367 -35% $7,488 $3,178 $4,311 -42%

118 Note: Includes Royalty Trusts

Pro Forma SandRidge NAV Post Permian Divestiture

SandRidge—Reserves / Resources / NAV

SandRidge YE2012 Permian Divestiture SandRidge Pro Forma

Area Locations MMBoe PV10 $MM Locations MMBoe PV10 $MM Locations MMBoe PV10 $MM

Resv + Resv + Resv + Resv + Resv + Resv + Resv + Resv + Resv +

Resources Drilling Resources Resources Resources Drilling Resources Resources Resources Drilling Resources Resources

Mid-Continent

Mississippian 7,808 7,034 2,386 15,176 ———— 7,808 7,034 2,386 15,176

Other 1,677 967 55 140 ———— 1,677 967 55 140

Total 9,485 8,001 2,440 15,315 ———— 9,485 8,001 2,440 15,315

Permian 12,748 7,970 548 7,174 11,188 7,416 529 6,806 1,560 554 19 368

Offshore 740 102 87 2,128 ———— 740 102 87 2,128

WTO/Other 6,427 5,429 834 2,258 ———— 6,427 5,429 834 2,258

Total 29,400 21,502 3,908 $ 26,875 11,188 7,416 529 $ 6,806 18,212 14,086 3,379 $ 20,069

• NAV at Modified 2/4/2013 Strip (Escalated & Capped $100/Bbl and $5.00/Mcf) Unhedged

119 • Adjusted for Royalty Trusts

• Excludes $1.7B NAV for KS appraisal area

Questions & Answers

Appendix

Guidance

and

Modeling Assumptions

2013 Operational Guidance

Production Differentials

Oil (MMBbls) (a) 15.9 Oil (a) $8.50

Natural Gas (Bcf) 110.4 Natural Gas $0.45

Total (MMBoe) 34.3

Capital Expenditures ($ in millions) Cost per Boe

Exploration and Production $1,450 Lifting $14.50— $16.50

Land and Seismic 100 Production Taxes 1.00— 1.20

Total Exploration and Production $1,550 DD&A—oil & gas 16.50— 18.30

Oil Field Services 30 DD&A—other 1.80— 2.00

Midstream and Other 170 Total DD&A $18.30— $20.30

Total Capital Expenditures (excl. Acquisitions) $1,750 G&A—cash 4.00— 4.45

G&A—stock 1.35— 1.50

Shares Outstanding at End of Period (in millions) Total G&A $5.35— $5.95

Common Stock 498 Interest Expense $8.10— $9.10

Preferred Stock (as converted) 90

Fully Diluted 588

EBITDA from Oilfield Services,

Midstream, and Other ($ in millions) (c) $30

Adjusted Net Income

Corporate Tax Rate (b) 0% Attributable to Noncontrolling Interest ($ in millions) (d) $150

Deferral Rate 0% P&A Cash Cost ($ in millions) $120

Includes NGLs

As a result of the Permian divestiture, the company expects to incur cash taxes of approximately $15 million in 2013 with a corresponding expense included in Net Income

EBITDA from Oilfield Services, Midstream and Other is a non-GAAP financial measure as it excludes from net income interest expense, income tax expense and depreciation, depletion and amortization. The most directly comparable GAAP measure for EBITDA from Oilfield Services, Midstream and Other is Net Income from Oilfield Services, Midstream and Other. 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 and/or does not forecast the excluded items on a segment basis

Adjusted Net Income Attributable to Noncontrolling Interest is a non-GAAP financial measure as it excludes unrealized gain or loss on derivative contracts and gain or loss on sale of assets. The most directly comparable GAAP measure for Adjusted Net Income Attributable to Noncontrolling Interest is Net Income Attributable to

Noncontrolling Interest. 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

122

2013 SandRidge Guidance Model – Production Revenue

($ in millions, except per unit amounts) Gas Oil (a) Total

Production (Bcf, MMBbls, MMBoe) 110.4 15.9 34.3

Price Assumptions:

NYMEX (b) $3.45 $94.02

Differential $0.45 $8.50

Projected Price (excl. effect of hedges) $3.00 $85.52

Wellhead Revenue $331 $1,360 $1,691

Impact of Hedges $2 $59 $61

Production Revenue (incl. effect of hedges) $333 $1,419 $1,752

a) Includes NGLs

b) Strip pricing as of February 21, 2013

• $1.00 increase in Crude Oil price creates additional EBITDA of $0.7MM; $0.10 increase in Natural Gas price creates additional EBITDA of $9.2MM

123

2013 SandRidge Guidance Model – EBITDA

($ in millions)

E&P EBITDA:

Production Revenue $1,752

Lifting, Tax, and G&A Costs 763

E&P EBITDA $989

Oilfield Services, Midstream, and Other EBITDA $30

Non-Controlling Interest EBITDA (210)

Non-Cash Stock Compensation 49

SD Model EBITDA $858

124

2013 SandRidge Guidance Model – Capital Expenditures

125

Hedging Overview

Strong hedge program provides downside protection in volatile commodity markets—Target 75-85% of current year production hedged

Continue to use derivatives to ensure financial stability

Oil 1Q13 2Q13 3Q13 4Q13 2013 2014 2015

Swaps

Volumes (MMBbls) 4.53 3.44 3.36 3.34 14.67 7.51 5.08

Price ($/Bbl) $97.56 $98.84 $98.62 $98.46 $98.31 $92.43 $83.69

Three-way Collars

Volumes (MMBbls) ————— 8.21 2.92

Call Price ($/Bbl) ————— $100.00 $103.13

Put Price ($/Bbl) ————— $90.20 $90.82

Short Put Price ($/Bbl) ————— $70.00 $73.13

LLS Basis

Volumes (MMBbls) 0.27 0.27 —— 0.54 — -

Price ($/Bbl) $15.16 $12.51 —— $13.83 — -

Natural Gas

Swaps

Volumes (Bcf) —————— -

Price ($/Mcf) —————— -

Collars

Volumes (Bcf) 1.71 1.71 1.72 1.72 6.86 0.94 1.01

Call Price ($/Mcf) $6.71 $6.71 $6.71 $6.71 $6.71 $7.78 $8.55

Put Price ($/Mcf) $3.78 $3.78 $3.78 $3.78 $3.78 $4.00 $4.00

• As of 2/26/2013

126 • Hedge positions include contracts that have been novated to or the benefit of which have been conveyed to SandRidge sponsored royalty trusts

• SandRidge has 0.2 MMBbls of oil collars in 2013 at an average ceiling price of $102.50 and an average floor price of $80

Net Asset Value – Pro Forma 2012 Year End

(in millions) 2012A

PV-10 $4,311

Resources $15,758

Projected Asset Value $20,069

Less: Net Debt (a) $1,469

Net Asset Value $18,600

Fully-Diluted Shares Outstanding 582

Net Asset Value per Share $31.98

127 a) Pro Forma for proceeds from the Permian divestiture, after debt reduction

Capitalization & Credit Ratio Progression

$ in millions

December 31, 2010 December 31, 2011 December 31, 2012 Pro Forma Adjustments P.F. December 31, 2012

Capitalization

Cash & Cash Equivalents $6 $208 $310 $1,415 $1,725

Debt

Current Maturities of LT Debt $7 $1 $0 $0 $0

Senior Credit Facility 340 0 0 0 0

Senior Notes 2,546 2,798 4,301 (1,107) 3,194

Other 16 15 0 0 0

Total $2,909 $2,814 $4,301 ($1,107) $3,194

Equity $1,536 $1,626 $2,369 NA $2,368

Noncontrolling interest 11 923 1,494 0 1,494

Total Book Capitalization $4,456 $5,363 $8,163 ($1,107) $7,056

Credit Statistics

Net Debt $2,903 $2,606 $3,991 ($2,522) $1,469

Pro Forma LTM Adjusted EBITDA(a) $733 $629 $1,183 ($436) $748

Leverage(b) 3.8x 4.3x 3.4x — 2.0x

Adjusted EBITDA / Interest(c) 3.2x 2.8x 3.4x — 3.0x

Net Debt / Proved Reserves ($/Boe) $5.32 $5.54 $7.05 — $4.00

Net Debt / Proved Developed Reserves ($/Boe) $13.04 $11.31 $12.48 — $7.01

Net Debt / Daily Production(d) $46.55 $39.30 $37.37 — $17.51

Net Debt / Total Capitalization 65% 49% 49% — 21%

• Contains Non-GAAP financial measures. Please see our website for reconciliations

4Q10 is Pro Forma for the Arena Acquisition. 4Q11 is Pro Forma for the East Texas divestiture . 4Q12 is Pro Forma for the Tertiary sale and the Dynamic and Hunt acquisitions. 4Q12 P. F. is Pro Forma for the Permian and Tertiary sales and the Dynamic and Hunt acquisitions.

128 c) Interest expense is calculated as cash interest expense on Senior Notes and Revolver

d) Based on the year’s fourth quarter average daily production

Contact: Kevin R. White, SVP – Business Development

Address: 123 Robert S. Kerr Avenue, Oklahoma City, OK 73102 | Phone: 405-429-5515 Email: kwhite@SandRidgeEnergy.com | Website: www.SandRidgeEnergy.com

ADDITIONAL INFORMATION AND WHERE TO FIND IT

On January 18, 2013 the Company filed with the SEC a definitive consent revocation statement in connection with the consent solicitation by TPG-Axon Partners, LP, TPG-Axon Management LP, TPG-Axon Partners GP, L.P., TPG-Axon GP, LLC, TPG-Axon International, L.P., TPG-Axon International GP, LLC, Dinakar Singh LLC, Dinakar Singh, Stephen C. Beasley, Edward W. Moneypenny, Fredric G. Reynolds, Peter H. Rothschild, Alan J. Weber and Dan A. Westbrook (the “TPG-Axon Consent Solicitation”), and has mailed the definitive consent revocation statement and a form of WHITE consent revocation card to stockholders of the Company entitled to execute, withhold or revoke consents relating to the TPG-Axon Consent Solicitation. STOCKHOLDERS OF THE COMPANY ARE URGED TO READ THE CONSENT REVOCATION STATEMENT, which is available now, AND OTHER DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Stockholders may obtain a free copy of the consent revocation statement and other documents (when available) filed with the SEC by the Company through the website maintained by the SEC at www.sec.gov.

CERTAIN INFORMATION REGARDING PARTICIPANTS

The Company and certain of its directors and executive officers are participants in the solicitation of consent revocations from the Company’s stockholders in connection with the TPG-Axon Consent Solicitation. Stockholders may obtain information regarding the names, affiliations and interests of the Company’s directors and executive officers in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, which was filed with the SEC on February 27, 2012, its Quarterly Reports on Form 10-Q for the first three fiscal quarters of the fiscal year ending December 31, 2012, filed on May 7, 2012, August 6, 2012 and November 9, 2012, respectively, and its definitive consent revocation statement, which was filed with the SEC on January 18, 2013. These documents can be obtained free of charge through the website maintained by the SEC at www.sec.gov.

About SandRidge Energy, Inc.

SandRidge Energy, Inc. is an oil and natural gas company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge and its subsidiaries also own and operate gas gathering and processing facilities and CO2 treating and transportation facilities and conduct marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and operates a drilling rig and related oil field services business. SandRidge focuses its exploration and production activities in the Mid-Continent, Gulf of Mexico, west Texas and Gulf Coast. SandRidge’s internet address is www.sandridgeenergy.com.

SandRidge Energy Contact:

Kevin R. White

Senior Vice President

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, OK 73102

+1 (405) 429-5515