Lm010815 investor-presentation-gs

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Thursday, January 8, 2015

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This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that conveyprojected future events or outcomes. The forward-looking statements include statements about the company’s future operations, development plans andappraisal programs, drilling inventory and locations, reserves, acreage positions, corporate strategies, rates of return, projected capital expenditures and othercosts, liquidity, debt maturities, price realizations and hedging strategies. We have based these forward-looking statements on our current expectations andassumptions 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 ourexpectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering,estimating, and developing oil and natural gas reserves, the availability and terms of capital, our timely execution of hedge transactions, credit conditions ofglobal capital markets, changes in economic conditions, regulatory changes and other factors, many of which are beyond our control. We refer you to thediscussion of risk factors in Part I, Item 1A – “Risk Factors” of our amended Annual Report on Form 10-K/A for the year ended December 31, 2013 and incomparable “Risk Factors” sections of our Quarterly Reports on Form 10-Q filed after the date of this presentation. All of the forward-looking statements madein this presentation are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantiallyrealized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees offuture performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake noobligation 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 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 amended Annual Report on Form 10-K/A 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.

DISCLAIMERForward Looking Statement

www.SandRidgeEnergy.com 2

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SANDRIDGE MISSIONPremier Mid‐Continent Company

MISSION STATEMENT

Our Mission at SandRidge is to create the premier,

high-return, growth-oriented, resource conversion company, focused in the Mid-Continent region of the United States.


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a) Non-GAAP financial measure. Refer to the Disclaimer slide for additional disclosure

b) Pro Forma for the Q1’14 Gulf of Mexico divestiturec) SandRidge consolidated reserves as of YE2013 including royalty trustsd) Based on YE13 SEC pricing ($93.42/$3.67)

SANDRIDGE COMPANY OVERVIEW

MARKET VALUE ($ in millions)

Market Cap (1/5/2015) $742

Net Debt(a) 2,605

Preferred Stock 565

Enterprise Value $3,912

ASSET OVERVIEW(b)(c)

Q3’14 Production (MBoe/d) 79.7

Proved Reserves (MMBoe) 377

% Reserves as Liquids 46%

YE13 PV10 Value ($Bln)(d) $4.1

• Fractured Carbonate Focus

• Mid-Continent, Horizontal Mississippian Leader

• Sub-$3.0MM/well, 380 MBoe EUR

• Stacked Pay Development

• 2014 Capex Plan of $1.55Bln

• $590MM Cash at Q3’14

SD Quick Facts


Focus Area Asset Map

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FOCUSEDLOWER PRICES INFLUENCE 2015Activity, Tactics, and Costs


Finalizing 2015 Capital Budget Plans, Will Announce in February • Strong liquidity and hedging plus reduced capital spending

− $900MM credit facility fully undrawn; material 2015 liquids hedging

− Reducing rig count, high-grading locations, using existing infrastructure

• Commercial returns at current commodity prices to be enhanced by lower well costs

− Some multilaterals already below $2.3MM per lateral

− Reduction in service costs could see ~$2MM per lateral

• Desire to maintain operational momentum and capabilities by:

− Continue innovating for lower well costs

− Continue expansion into new zones and areas

• Will look to improve and simplify the balance sheet in this market

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SCALE & OPERATION

FOCUS

SANDRIDGE ENERGYScale, Focus, Discipline


Activity

• Q3 2014 total company production of 80 MBoe/d, with 67 MBoe/d in Midcontinent

• Mississippian position of 670,000 core acres, 55% HBP

• ~30 active rigs, >400 horizontal laterals per year

• ~40% production growth year-over-year in focus area

• Adding Chester, Woodford and other zones to Mississippian core

• >1.2 MMBw/d Saltwater Gathering (SWG) Operation

Financial Discipline: Cost Leader, Eye On Infrastructure Value Capture

• <$3MM per 4500’ Mississippian lateral

• Multilateral cost breakthrough: <$2.4MM per lateral

• S1 filed for SWG MLP

• Cycle time reductions and shared facility costs continue; more to come

• Focus on artificial lift program moderates base decline rates

7www.SandRidgeEnergy.com 7

• Mississippian development leader: high capacity to execute on large scale stacked pay acreage footprint

• Cost focus (per lateral, with facility and infrastructure efficiencies and asset value)

• New Ventures: adjacent zone, acreage and new play upsides

• Innovation: multilateral cost breakthrough

• Leverage scale and capabilities

• Infrastructure monetization strategy (S1 for SWG)

SANDRIDGE ENERGYMidcontinent Scale, Capability and Upside

STRATEGY & ASSET OVERVIEW

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GROWTH PLATFORM WITH UPSIDES

Stacked Oily Pay Zones

Significant Acreage Position

Improving Already Strong Returns

FOCUSED


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• Best in class Mid-Continent drilling and completion (D&C) lateral costs

– $2.9MM per Mid-Continent single lateral

– $700M decrease in well cost since 2012

– 100% electric submersible pump (ESP) implementation rate in Q3’14

• Primary D&C cost saving in 2014 linked to innovation championed by SD teams:

– Pad drilling: 74% of Q3’14 wells drilled from multi-well pads

– Multilateral drilling: Stacked and Co-planar Dual Laterals, Trilateralsand Full Section Development

– Wellsite facilities design improvements:– Centralized tank batteries– Commingled tank batteries– Centralized Salt Water Disposal (SWD) systems

FOCUSEDMATERIAL WELL COST AND LOE REDUCTIONMississippian Leader


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FOCUSEDWELL COSTS CONTINUE TO IMPROVEPlan $2.8mm For 2015 and Lower In 2016


• Continuous improvement has reduced well costs from $3.6MM in 2012 to $2.9MM in 2014

• Multilaterals are now ~20% of the program, recently at $2.4MM per lateral

• Continued cost control initiatives plus less cost pressure given lower oil prices suggest sub-$2.7MM per lateral in 2016

Source of Additional Cost Decreases:• Produced Water Fracs

• Multilaterals

• Ball Drop Completions

• Shared Tanks

• Pad Drilling

• Cost Control

• Lower Service Costs

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TARGETING BREAKOUT ECONOMICSAhead of Schedule, Reducing Well Costs INNOVATION

• Hedges maintain strong well economics that are improving as costs come down

• Breakout innovations on well design could both:

– Enhance returns

– Expand focus areas

• Value enhancing projects in motion

– Completion techniques

– Sectional development

– Shared facilities

– Artificial lift management system

• Expand competitive advantages

− Salt water disposal

− Electrical distribution system

• Multi-zone appraisal program


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2014 MISSISSIPPIAN PUD TYPE CURVE Actual Performance Consistently Above Type Curve FOCUSED

GAS: 1.2 Bcf

30 Day IP(b) (Mcf/day)1st Year Decline(a)

B Factor

84865%1.83

NGL: 64 MBbls

Yield (Bbls/MMcf)Shrink

47.587.3%

Oil: 118 MBo

30 Day IP (Bo/day)1st Year Decline(a)

B Factor

17680%1.41

a) Represents decline from month 1 to month 13b) Wet gas, wellhead volumes


As of 12/10/2014

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Type Curve 176 Bbl/d

MISSISSIPPIAN WELL PERFORMANCEContinued Improvement

MULTI-YEARGROWTH

Type Curve 849 Mcf/d


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MID‐CONTINENT FOCUS AREA Deep Understanding of the Play FOCUSED

100 MILES SD LEASEHOLD

• Shallowest Decline Profile• Higher EUR Distribution• Geology Most

Understood• Stacked Pay Potential

• Chester Delivering Above TC Oil Rates

• Multi Laterals Decreasing per Lateral CAPEX

• High Density FracsPotentially Impactful

• Highest 30 Day Gas IPs• Low H2O Cut• Upside as Gas Prices Rise

• 3D Required to Define Fracture Trends• Positive Multi Lateral Results

• Highest 30 Day Oil IPs• Highest Liquids %• Lowest H2O Cut• Improving EURs with Time• Dual Laterals Exceeding TC

~650,000 Acres in Focus Area

• Miss Exhibiting Tightest Performance Distribution

• Unlocked Woodford Potential• Potential for Extensive Multi

Lateral Development


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FOCUSEDMULTI‐ZONE DRILLING LOCATIONS Many Years of Drilling Ahead

Upper MissHZ Wells to Sales 1,150

MarmatonHZ Wells to Sales 1

ChesterHZ Wells to Sales 35

Middle MissHZ Wells to Sales 161

Lower MissHZ Wells to Sales 17

WoodfordHZ Wells to Sales 11

High-Graded Locations to Drill 4,510 wellsUn-Risked Locations >8,000 wellsEmerging development

Note: Drilling location information as of 12/31/14


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NEW VENTURES CASE STUDYChester Oil Development INNOVATION

• Horizontal development of legacy vertical production

• Fine grained silty sandstone, 2 distinct pay intervals

• Existing infrastructure in area

• Higher oil cut and less water production than Miss carbonates

• Stacked lateral potential (Chester A + B)

• 2013 appraisal with 4 wells, 35 producers now online

• ~$134MM (Gross) capital investment to-date

• Growth potential with appraisal success to the southand west of core counties

• IP: 368 Boe/d (64% oil), 16% above Miss Type Curve


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APPLYING SEISMIC TECHNOLOGYUnderstanding the Rock INNOVATION

KS

OK

100 MILES

+25% of core counties with 3d coverage+45% of ok core counties with 3d coverage2013 - 730 square miles of 3D data acquired2014 - 1,070 square miles of new 3D data acquired

Parallel fault trend

Main fault trend


3d seismic reveals:• Fractures• Faulting• Rock mechanics• Reservoir compartments• New plays

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Achieving Breakthrough Cost Upsides with Production Uplift

MULTILATERAL APPROACH IS SUCCESSFULChanging How Carbonates are Developed INNOVATION

• Multilateral success achieved on three dual stacked laterals and one co-planar well in Grant, Alfalfa, and Harper counties during Q2’14

• Four Q2’14 wells averaged $2.5MM per lateral

– 83% of type curve cost

– 108% of the type curve 30-day IP

• Six Q3’14 wells averaged $2.4MM per lateral

• Six rigs are currently planned to drill multilateral wells through the second half of the year

• Broader sanction of multilaterals expected in 2015

– Multilaterals made up 21% of the Q3’14 drilling program (two or more laterals from a single vertical well)

Dual Stacked Lateral

Co-Planar Dual Lateral


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INNOVATION / UPSIDE FSD Offers Up to 34% More Section for 26% less capexFull Section Development • Fracture stimulates 34% more interval: 22,000’ vs typically 16,400’ with four single

laterals

• Rock integrity of our carbonates (vs shales or sandstones elsewhere) allows for effective use of open hole multilaterals

• 130% IRR* to drill and complete a multilateral Full Section Development at $2.3MM per lateral vs 65% IRR* for a single lateral well at $2.9 MM

• $3.2MM savings per square mile section ($9.1MM vs $12.3MM):

INNOVATION

(For Illustrative Purposes)

Full Section Development

Full Section Development D&C Cost Savings Detail $MTank Battery, SWD, Powerline and Connection $ 1,350 Intermediate 7" Casing and ESP Savings (One Each vs Four) $ 1,100 Drilling Location, Rig Move and Reduced Drilling Days $ 1,000 Rentals and Miscellaneous $ 350 Incremental cost to frac an additional ~6000’ of interval $ (600)

Total Savings $3,200

* Strip as of 8/1/14 www.SandRidgeEnergy.com 19

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FULL SECTION DEVELOPMENT CASE STUDY$2.1 MM Per Lateral, Over 4x Type Curve From 4 Laterals


INNOVATION

• Development Model:

– Full section development candidates are areas with geologically and economically proven reservoirs in the Miss Lime

– Cost savings yield enhanced returns

– May allow for profitable development of marginal areas

• Operations:

– Laterals were drilled without any delays or problems

– Simultaneous operations utilized successfully

– Stratigraphic section changed in first lateralleading to target change in #2

– Completed and online 9/24

Kirkpatrick Farms: First FSD Well, $8.32MM Well CostPeak 30-Day IP: 1,086 Boe/d (60% Oil)

10,000Water

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SALTWATER GATHERING & DISPOSAL (SWG) UPSIDES

• Produce

– ~1.2 million barrels of water gathered and disposed per day during Q3‘14 in the 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 cleaned and treated at disposal location

• Inject

– + 180 disposal wells as of mid-2014, adding ~50 wells per year

– Many take water on a vacuum (hydrostaticpressure is adequate to achieve disposal)

• Estimate ~$600MM invested by the end of 2014

• Average capacity of 15,000 BWPD per well

– Low pressure pumps at most locations

– Various tubing sizes based on needed capacity

– Open hole Arbuckle completion

• Pressure and volume continuously monitored

• Arbuckle has been taking produced water for ~80 years

• Frac flowback is < 5% of total

• Gathering system is interconnected – maximizing system flexibility

Most Efficient SWG Operator in

the midcontinent

Produced Water Gathered and Sequestered into Arbuckle Through Cost Effective Infrastructure


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Focus and Innovation Yield Exceptional Operating Results

Operational Update• Third quarter total company production 80 Mboe/d, 14% growth quarter-over-quarter

• Mid-Continent production grew 39% year-over-year and 19% quarter-over-quarter to 67 Mboe/d

─ IPs remain above type curve─ 129 laterals drilled in third quarter with 33 rigs running─ Multilaterals applied successfully at $2.4MM per lateral

• $75MM increase in 2014 capex, mainly for land and seismic

Financial Activity• Material hedging of oil prices over $90/Bbl through 2015

• Repurchased 27.4MM shares at $4.06, 5.6% of outstanding shares

• Credit facility upsized to $900MM; undrawn availability, expandable to $1.2 Bln

Other Themes

• Continued success in Chester and Woodford

• Capital efficiencies continue to drive increased returns

• Power infrastructure enhanced with new auto-restarts and addition of substation

APPENDIXQ3’14 – CONTINUED STRONG WELL RESULTS


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2014 PRODUCTION GUIDANCE UPDATE

(A) 2013: 11.3 MMBoe of non-recurring production related to divested Permian and GoM assets(B) 2014: 1.3 MMBoe of non-recurring production related to divested GoM assets (2/25/2014 closing)


APPENDIX

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• Contains Non-GAAP financial measuresa) Leverage Ratio represents Consolidated Leverage Ratio calculated pursuant to

the terms of the Senior Credit Facility b) Liquidity represents the quarter ending cash balance and revolver availability,

adjusted for letters of creditc) Revolver is expandable to $1.2B with written request

• ~$1.5 Bln liquidity at Q3’14

– $590MM cash

– Fully undrawn credit facility of $900MM(c)

• 3.4x Q3’14 leverage ratio

• Significant oil hedges at strong prices provide cash flow stability and visibility

CREDIT PROFILEAbility to Maintain Adequate Liquidity, Reasonable Leverage APPENDIX


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(a) Convertible at holder’s option at $8.0125 per common share; convertible after Feb 20, 2014 (b) Convertible at holder’s option at $7.7645 per common share; convertible after Nov 20, 2015 (c) Weighted Average Maturity excludes Credit Facility amounts

Senior Notes

8.75% Sr Notes due 2020 $4457.5% Sr Notes due 2021 1,1798.125% Sr Notes due 2022 7507.5% Sr Notes due 2023 821

Total $3,195

($ in millions)

Credit Rating Corp Rating Outlook

(c)

(c)

Preferred Stock ($ in millions)

8.5% Convertible Perpetual Preferred (a) $2657.0% Convertible Perpetual Preferred (b) 300

Total $565

Moody’s B1 StableS&P B Stable

Credit Rating Corp Rating Outlook

CAPITAL STRUCTURE OVERVIEWNo Principle Currently Due until 2020 APPENDIX


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• As of 01/06/2014• Hedge positions include contracts that have been novated to or the benefit of which have been conveyed to SandRidge sponsored royalty trusts

HEDGING OVERVIEW APPENDIX

To be updatedLiquids Q1 2015 Q2 2015 Q3 2015 Q4 2015 2015 2016

SwapsVolumes (MMBbls) 2.29 1.73 1.01 0.55 5.59 1.46Price ($/Bbl) $92.71 $91.55 $92.43 $94.11 $92.44 $88.36

Three-way Collars Volumes (MMBbls) 0.72 0.73 1.56 1.56 4.58 2.56Call Price ($/Bbl) $103.13 $103.13 $103.65 $103.65 $103.48 $100.85Put Price ($/Bbl) $90.82 $90.82 $90.03 $90.03 $90.28 $90.00Short Put Price ($/Bbl) $73.13 $73.13 $78.15 $78.15 $76.56 $83.13

Natural Gas Q1 2015 Q2 2015 Q3 2015 Q4 2015 2015 2016

Swaps

Volumes (Bcf) 14.40 1.82 1.84 1.84 19.90 0.00Price ($/Mcf) $4.62 $4.20 $4.20 $4.20 $4.51 NA

CollarsVolumes (Bcf) 0.25 0.25 0.25 0.25 1.01 0.00Call Price ($/Mcf) $8.55 $8.55 $8.55 $8.55 $8.55 NAPut Price ($/Mcf) $4.00 $4.00 $4.00 $4.00 $4.00 NA

Basis Swaps (PEPL)Volumes (Bcf) 5.40 5.46 5.52 5.52 21.90 0.00Swap Price ($/Mcf) ($0.273) ($0.273) ($0.273) ($0.273) ($0.273) NA


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RESERVES PV10 Liquids

MMBbls Gas Bcf

Equivalent MMBoe

% $MM %

Reserves by Reservoir Status

PDP - Producing 88 708 206 55% $ 2,441 59%

PNP - Non Producing 9 57 19 5% 283 7%

PBP - Behind Pipe 1 74 14 4% 73 2%

PUD - Undeveloped 74 384 138 37% 1,306 32%

Total 173 1,223 377 $ 4,103

Reserves by Development

Total Developed 98 839 238 63% 2,797 68%

Total Undeveloped 74 384 138 37% 1,306 32%

Total 173 1,223 377 $ 4,103

Pro Forma 2013 Excluding Gulf of Mexico Proved Reserves*SEC Pricing - $93.42 / $3.67

434% Reserve Replacement

63% Proved Developed

25% Reserve Growth

$10.19 Organic Drilling F&D

$11.72 All-In F&D

16.7 Years of R/P Life

* Adjusted for Permian & Gulf of Mexico divestitures• Includes non-controlling royalty trust interests

2013 RESERVE METRICSFocused on the Mississippian Play APPENDIX


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40

60

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100

120

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100

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Cum

ulative Production (Mboe)

Avg

. Boe

/d

Type Curve Daily Avg. Rate Type Curve Cum Production

1 2 3 4 5 6 7 8 9 100Years

GAS: 1.2 Bcf

30 Day IP(b) (Mcf/day)1st Year Decline(a)

B Factor

84865%1.83

NGL: 64 MBbls

Yield (Bbls/MMcf)Shrink

47.587.3%

Oil: 118 MBo

30 Day IP (Bo/day)1st Year Decline(a)

B Factor

17680%1.41

2014 MISSISSIPPIAN PUD TYPE CURVE 380 MBoe, 48% Liquids

a) Represents decline from month 1 to month 13b) Wet gas, wellhead volumes

Type Curve EUR YE2013Oil (Mbo) 118

NGLs (MBbls) 64

Liquids (MBbls) 182Gas - Shrunk (MMcf) 1,185

MBoe 380

Mcf Shrink 87.3%

NGL Yield (Bbls/MMcf) 47.5


APPENDIX

As of 12/10/2014

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2014 OPERATIONAL GUIDANCE UPDATE

PRODUCTIONOil (MMBbls) 10.8 - 11.2Natural Gas Liquids (MMBbls) 3.6 - 3.7

Total Liquids (MMBbls) 14.4 - 14.9Natural Gas (Bcf) 83.5 - 84.8Total (MMBoe) 28.3 - 29.0

CAPITAL EXPENDITURES ($ in millions)Exploration and Production $1,275Land and Seismic 170

Total Exploration and Production $1,445Oil Field Services 15Electrical/Midstream 40General Corporate 50

Total Capital Expenditures (excl. A&D) $1,550

EBITDA from Oilfield Servicesand Other ($MM) (a) $30

Adjusted Net Income Attributable to NCI ($MM) (b) $110

Adjusted EBITDAAttributable to NCI ($MM) (c) $145

PRICE REALIZATIONSOil (differential below WTI) $2.60NGLs (realized % of WTI) 36%Gas (differential below Henry Hub) $0.65

COSTS PER BOELifting $11.15 - $13.15Production Taxes 1.10 - 1.20DD&A – oil & gas 15.00 - 16.75DD&A – other 2.10 - 2.30Total DD&A $17.10 - $19.05

G&A – cash 3.35 – 3.55G&A – stock 0.60 - 0.70Total G&A $3.95 - $4.25

Corporate Tax Rate 0%Deferral Rate 0%

a) EBITDA from Oilfield Services 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 and Other is Net Income from Oilfield Services 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

b) Adjusted Net Income Attributable to Noncontrolling Interest is a non-GAAP financial measure as it excludes gain or loss due to changes in fair value of 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

c) Adjusted EBITDA Attributable to Noncontrolling Interest is a non-GAAP financial measure as it excludes from net income interest expense, income tax expense and depreciation, depletion and amortization, gain or loss due to changes in fair value of derivative contracts and gain or loss on sale of assets. The most directly comparable GAAP measure for Adjusted EBITDA 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


APPENDIX

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SANDRIDGE INVESTOR RELATIONS123 Robert S. Kerr Avenue, Oklahoma City, OK 73102

[email protected]

www.SandRidgeEnergy.com

Our Mission at SandRidge is to create the premier, high-return, growth-oriented, resource conversion company, focused in the Midcontinent region of the United States.

Lm010815 investor-presentation-gs

Investor Relations

cautionary statements

natural gas reserves

future developments

possible reserves

thediscussion of risk

current conditions

actual results

companys future operations