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DISCLAIMER
FORWARD LOOKING STATEMENT
This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that
convey projected future events or outcomes. The forward-looking statements include statements about the company’s corporate strategies, future
operations, development plans and appraisal programs, and projections and estimates of our drilling inventory and locations, production, reserves, rates of
return, projected capital expenditures and other costs, efficiency initiative outcomes, infrastructure utilization and investment, liquidity, debt maturities,
capital structure, asset sales, price realizations and hedging strategies. We have based these forward-looking statements on our current expectations and
assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future
developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform
with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in
discovering, estimating, and developing oil and natural gas reserves, the availability and terms of capital, our timely execution of hedge transactions, credit
conditions of global capital markets, changes in economic conditions, regulatory changes and other factors, many of which are beyond our control. We refer
you to the discussion of risk factors in Part I, Item 1A – “Risk Factors” of our amended Annual Report on Form 10-K/A for the year ended December 31, 2013
and in comparable “Risk Factors” sections of our Quarterly Reports on Form 10-Q filed after the date of this presentation. 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 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.
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SUCCESS DEMONSTRATED BY HITTING GROWTH GUIDANCE AND ADDING RESERVES
• Reserves up 37%, PUD type curve up 27%
• 2014 production of 29 MMBoe, 1% over guidance; MidCon grew 47% YOY to Q4’14 76 MBoe/d
IMPROVED CAPITAL EFFICIENCY THROUGH 2015 AND INTO 2016
• $2.4MM lateral cost target for 2H’15
• Lower lateral cost and improved type curve provide 27% more EUR for 80% of cost
• 2014 multilateral program at 85% of cost of single laterals for 100% of 90-day type curve volume
NEW COVENANT PROVIDES BALANCE SHEET FLEXIBILITY
• $900MM borrowing base affirmed in February
• 2.25x senior secured covenant
INTRODUCING 2015 GUIDANCE - PRESERVES LIQUIDITY AND PRODUCTION BASE
• $700MM Capex, ~6% organic production growth
• Ramping down from current 19 rigs to 7
• 40% of 2015 program comprised of multilaterals
ACTIONS TO THRIVE IN LOWER PRICE ENVIRONMENT
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Development inventory is preserved with lower
costs and expanded with oil price recovery
returns are preserved…At lower well costs…
drilling location count grows.
Service cost reductions plus increased
efficiencies while drilling more multilaterals
Type curve returns at target costs and
current strip comparable to 35% IRRs from
higher price and cost environment in 2014
27% MORE EUR FOR 80% OF THE COST
* 02.13.15 Strip Pricing
* PUDs + Risked Probables @ Strip
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PRINCIPLES
Drilling projects must generate hurdle
returns at strip pricing
Unlock value in this market
• Efficiency gains
• Service cost reductions
• Expanded use of multilaterals
Efficient infrastructure utilization
Transition toward operating
within cash flows
Defend and Extend capabilities
PLANNED SPEND AND RESULT
$700MM Capex budget
28.0-30.5 MMBoe guided production
~ 6% Year-over-Year volume growth
Quick ramp down to lower rig count
Appraisal New Ventures commitment
40% multilaterals in drilling plan
2015 CAPEX OF $700MM VS. $1.6B IN 2014
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Note: SandRidge consolidated reserves as of YE 2014 including royalty trusts
(a) Based on YE 2014 SEC pricing ($91.48/4.35)
(b) 02.13.15 Strip Pricing
• 516 MMBoe (+37% YOY)
• $5.5B SEC PV-10(a)(+34% YOY)
• $3.3B PV-10(b) at Strip
• 604% All-in Reserve Replacement
• 65% Proved Developed
YEAR END PROVED RESERVES +37%
• All-in F&D $9.00/Boe
• 42% Liquids Mix
• $10.69 Proven Value/Boe(a)
• 18.7 Years Reserve Life
• 12.2 Years Proved Developed
Reserve Life
RESERVES MIX
RESERVES GROWTH
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SandRidgeEnergy.com 7(a) Represents decline from month 1 to month 13 (b) Wet gas, wellhead volumesAs of 12.31.2014
2015 GAS: 1.6 Bcf
30 Day IP
(b)
(Mcf/d)
1st Year Decline(a)
B Factor
966
62%
2.00
2015 NGL: 97 MBbls
Yield (Bbls/MMcf)
Shrink
51.6
86.1%
2015 OIL: 118 MBo
30 Day IP (Bo/d)
1st Year Decline(a)
B Factor
190
80%
1.26
2015 MISSISSIPPIAN PUD TYPE CURVE
484 MBoe, 44% Liquids
MBoe
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MEANINGFUL WELL COST REDUCTIONS
EFFICIENCY GAINS
• Rig efficiency
• Location high-grading
• Wellbore + completion design
SERVICE COSTS
• Rig rates
• Directional drilling
• Stimulation
• Liner packer system
• ESPs
MULTILATERAL EXPANSION
• 40% multilaterals
• 85% of the cost of single
laterals for 100% of 90-day
type curve production
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• At target lateral cost of $2.4MM and 2015 type curve,
wells generate ~45% IRRs at recent strip, hedges
excluded
• Returns for these new costs and type curve are
comparable to returns from 2014 program
($3MM lateral cost, 2014 type curve, $80+ oil)
• Well cost reductions and type curve improvement offset
impact of lower oil prices; set foundation for enhanced
returns with price improvement
NEW COSTS AND EURs PRESERVE PRIOR RETURNS
* 02.13.15 Strip Pricing
27% More EUR for 80% of the Cost
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ACTIVITY AND SUCCESS IN 2014
• Sole multilateral operator in the Midcontinent
• Multilateral program consisted of 28 projects with average
completed well costs of $2.6MM per lateral
• Wells with greater than three months of production
averaged 100% of the 90-day type curve Boe
– 98% of 90-day type curve oil
– 102% of 90-day type curve gas
CAPITALIZING ON PROVEN INNOVATION IN 2015
• 40% Multilaterals in 2015 drilling plan
– Efficient allocation of capital
– Proven results
– Expanding an innovative concept throughout other areas
of core development
CAPITALIZING ON PROVEN INNOVATION
100% of 90-Day Type Curve Production for
85% of the Cost of a Single Lateral
FULL SECTION DEVELOPMENT
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MISS CHESTER WOODFORD*
Producing Laterals 1375 35 5
Peak 30-Day Boe 365 369 418
Future Locations (a)
3212 401 147
DRILLING LOCATION INFORMATION
MULTI-ZONE DRILLING LOCATIONS AND 2015 ACTIVITY
( As of February 2015)
* Wells developed under new geological model
(a) PUDs + Risked Probables @ 02.13.15 Strip
Ramp Down to 6 Development Rigs + 1 Committed to Appraisal New Ventures
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MONETIZATION OPPORTUNITIES
• Asset Sale Options
– SWG infrastructure
– Real Estate
– Non-core production
CAPITAL DISCIPLINE
• Capex Set at $700MM
• Capital Efficiency Gains
– Operational Improvements
– Service Cost Reductions
– Expanded use of Multilaterals
FINANCIAL POSITION
CAPITAL STRUCTURE FOCUS
• Ample Liquidity
– $900MM borrowing base
– New senior secured covenant (2.25x EBITDA beginning 3/31/15)
– No bond maturities before 2020
(a) $100MM drawn as of February 20, 2015
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2015 PRODUCTION GUIDANCE
(a) 2014: 1.3 MMBoe of non-recurring production related to divested GOM assets
Note: Totals may not foot due to rounding
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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 $7.7645 per common share; convertible after Nov 20, 2015
Senior Notes ($ in millions)
Credit Rating Corp Rating Outlook
Preferred Stock ($ in millions)
8.5% Convertible Perpetual Preferred (a) $265
7.0% Convertible Perpetual Preferred(b) 300
Total $565
Moody’s B1 Stable
S&P B Negative
Credit Rating Corp Rating Outlook
CAPITAL STRUCTURE OVERVIEW
(c) $100MM drawn as of February 20, 2015
8.75% Sr Notes due 2020 $450
7.5% Sr Notes due 2021 1,175
8.125% Sr Notes due 2022 750
7.5% Sr Notes due 2023 825
Total $3,200
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• As of 02.25.2015
• Positions displayed include royalty trusts, but are exclusive of basis hedges.
• Liquids hedged to NYMEX WTI; Natural Gas hedged to NYMEX Henry Hub; NGL barrels hedged at 3:1 ratio to WTI.
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STRONG HEDGE POSITION
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PRODUCE
• ~1.3 million barrels of water gathered and disposed per day
during Q4‘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
• 191 SWG wells in Mid-Continent and Permian Basin
• Many take water on a vacuum (hydrostatic pressure is
adequate to achieve disposal)
~$600MM INVESTED THROUGH 2014
• Average capacity of 15,000 Bw/d per well
– Low pressure pumps at most locations
– Various tubing sizes based on needed
capacity
– Open hole Arbuckle completion
• Pressure and volume continuously
monitored
• Arbuckle has been taking produced water
for ~80 years
• Frac flowback is < 5% of total
• Gathering system is interconnected –
maximizing system flexibility
MOST EFFICIENT SWG OPERATOR
IN THE MIDCONTINENT:
SALTWATER GATHERING & DISPOSAL (SWG)
99%
OF WATER
IS PIPED
(VS. TRUCKED)
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Note: Map does not show other SWG assets in NW Kansas or West Texas.
LARGEST SALTWATER GATHERING SYSTEM IN THE NATION
Hydraulic Modeling and Engineered Process Achieved >99% Pipe Efficiency
• 1,260 MBw/d current volumes
• 191 SWG wells
• 1,049 miles of installed pipelines
• Advanced hydraulic simulation
• Resembles hydrocarbon gathering
and processing system
• Design based on actual type curves
• Engineered design and construction
• New assets, built since 2008
• > 99% piped volumes
100 MILES
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PRODUCTION
Oil (MMBbls) 9.0 – 10.0
Natural Gas Liquids (MMBbls) 4.0 – 5.0
Total Liquids (MMBbls) 13.0 – 15.0
Natural Gas (Bcf) 89.5 – 93.5
Total (MMBoe) 28.0 – 30.5
CAPITAL EXPENDITURES ($ in millions)
Exploration and Production $612
Land and Geophysical 38
Total Exploration and Production $650
Oil Field Services 5
Electrical/Midstream 30
General Corporate 15
Total Capital Expenditures (excl. A&D) $700
EBITDA from Oilfield Services
and Other ($MM)(a) $10
Adjusted Net Income
Attributable to NCI ($MM)(b) $60
Adjusted EBITDA
Attributable to NCI ($MM)(c) $90
PRICE REALIZATIONS
Oil (differential below WTI) $3.75
NGLs (realized % of WTI) 30%
Gas (differential below Henry Hub) $0.75
COSTS PER BOE
Lifting $12.25 - $13.00
Production Taxes 0.65 – 0.85
DD&A – oil & gas 12.00 – 15.00
DD&A – other 2.00 – 2.20
Total DD&A $14.00 - $17.20
G&A – cash 3.00 – 3.50
G&A – stock 0.50 – 0.75
Total G&A $3.50 - $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.
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2015 OPERATIONAL GUIDANCE
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2015 CAPEX GUIDANCE
2015 CAPEX GUIDANCE 2015 GUIDANCE LATERAL COUNTS 2015 GROSS 2015 NET
Development D&C $306 Development 182 116
Appraisal & New Ventures D&C 29 Appraisal & New Ventures 11 8
Carryover 102 Total Laterals 193 124
Total D&C $437
SWG - D&C 11
Permian 0
JV Carry 0
Total D&C $448
OTHER E&P
Development Land & Geophysical $21
Appraisal & New Ventures Land & Geophysical 17
Total Land & Geophysical 38
SWG Infrastructure 27
Workovers & Non-Op 86
Capitalized G&A and Interest 51
Total Other E&P $202
NON E&P
Drilling & Oil Field Services $5
Midstream and Electrical 30
General Corporate 15
Total Non-E&P $50
TOTAL $700
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SANDRIDGE INVESTOR RELATIONS
123 Robert S. Kerr Avenue, Oklahoma City, OK 73102
investors@sandridgeenergy.com
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.
