1. business and industrial
2. energy
3. natural gas

INVESTOR PRESENTATION
MAY 2015
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 Annual Report on Form 10K for the year ended December 31, 2014 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 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.
SANDRIDGE HAS A LEADING U.S. MIDCONTINENT OIL & GAS POSITION
WE ARE SKILLED, LARGE SCALE DEVELOPERS OF OIL AND GAS RESOURCES
• 1,500 wells drilled, over $5B invested since 2010 ($1.6B in 2014)
• Producing ~90 MBoepd, largest water gathering system in U.S. (over 1.2 MMBwpd)
• Expert at horizontal redevelopment of legacy vertical oil and gas plays
TRANSFERABLE SKILLSETS TO OTHER PLAYS
•
•
•
•
•
Drilling: ran 30+ rigs in 2014, current $2.7MM cost per horizontal lateral
Infrastructure and logistics: optimizing extensive water and electrical systems
Production: Mid-Continent production grew 50% year over year to 76.2 MBoepd in Q1’15
Artificial Lift: optimizing gas lift, ESPs, and rod pumps
Engineering and geology: growing multi-year inventory of drilling locations
INNOVATION AND CONTINUOUS IMPROVEMENT ARE PART OF OUR CULTURE
•
•
•
•
Premier operator of the Mississippian Limestone in Oklahoma and Kansas
Developing stacked pays such as Chester and Woodford
Sole operator drilling multilateral wells
Cost leaders: well costs, production expense
BUSINESS MINDED CULTURE
• Management background includes oil majors, independents, midstream and Wall Street
• We efficiently accelerate value creation with large scale activity levels more typical
of larger companies
2015 BUDGET PHILOSOPHY REFLECTED IN Q1 RESULTS
EBITDA, PRODUCTION & SPEND RATE IN LINE WITH PLAN
• $182MM of adjusted EBITDA; adjusted earnings of $0.00 per diluted share
• Mid-Continent production of 76.2 MBoepd, up 50% vs Q1 2014
• Total Company production of 87.7 MBoepd, up 36% vs Q1 2014, pro forma for divestitures
• Mid-Continent Q1 laterals 30-day IP rates of 402 Boepd, 52% oil, 115% of type curve
• Front-end loaded capex of $322MM in Q1 vs $700MM full year guidance
TARGETED WELL COSTS OF $2.4MM PER LATERAL ACHIEVABLE IN 2H 2015
• Per lateral well costs preserving attractive economics of previous year’s costs and prices
• Estimated $2.7MM average drill and complete costs per Mississippian lateral in first quarter
• $350K of total $600K targeted well costs savings realized as of April 1st
• Continued expansion of multilateral program throughout remainder of 2015
DECREASED ACTIVITY IN REMAINDER OF 2015
• Currently running 7 rigs vs exit rate of 35 in 2014
• All active rigs drilling producers
• $400MM capex run rate in Q4 2015
27% MORE EUR FOR 80% OF THE COST
At lower well costs…
returns are preserved…
drilling location count grows.
Development inventory is preserved with lower
costs and expanded with oil price recovery
Service cost reductions plus increased
efficiencies while drilling more multilaterals
Type curve returns at target costs and
current strip exceed IRRs from higher
price and cost environment in 2014
* 5.1.15 Strip Pricing
* PUDs + Risked Probables @ Strip
2015 CAPEX OF $700MM VS. $1.6B IN 2014
Reducing Capital Spending While Increasing Efficiency
PRINCIPLES
Drilling projects must generate hurdle
returns at strip pricing
Unlock value in this market
• Efficiency gains
• Service cost reductions
• Expanded use of multilaterals
PLANNED SPEND AND RESULT
$700MM Capex budget
28.0-30.5 MMBoe guided production
Guiding 6% YoY volume growth despite
rig ramp down
7 Rigs currently running
Efficient infrastructure utilization
Appraisal New Ventures commitment
Transition toward operating
within cash flows
Defend and Extend capabilities
40% multilaterals in drilling plan
STRONG HEDGE POSITION FOR REMAINDER OF 2015
$251MM Mark-to-Market Hedge Book Value; $60 Oil in 2015 Realizes ~$83 per Bbl
*
• Positions displayed are from April forward
• 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
LIQUIDITY AND BALANCE SHEET FLEXIBILITY INTACT
Ample Liquidity, No Near Term Maturities
• $725MM liquidity; $900MM borrowing base
• 0.22x senior leverage ratio (senior secured debt/LTM pro forma EBITDA) vs
2.25x covenant
• No bond maturities before 2020
MARKET VALUE ($ in millions)
Market Cap (5/6/2015)
$857
Net Debt(1)(2)
3,359
Preferred Stock
Enterprise Value
565
$4,781
ASSET OVERVIEW(3)
Q1’15 Production (MBoepd)
87.7
Proved Reserves (MMBoe)
516
% Reserves as Liquids
42%
YE14 PV10 Value ($Bln)(4)
$5.5
1)
2)
3)
4)
(a) $175MM drawn as of March 31, 2015
Non-GAAP financial measure. Refer to the Disclaimer slide for additional disclosure
As of 3.31.15
SandRidge consolidated reserves as of YE2014 including royalty trusts
Based on YE14 SEC pricing ($91.48 / $4.35)
2014 ACHIEVEMENTS
Hit our Operating Stride in 2014, Now Focused on Balance Sheet
2014 FULL YEAR RESULTS
•
•
•
•
•
•
•
•
37% Proved reserves growth
27% Type curve growth
47% Midcon production growth
1% over production guidance midpoint
Added Garfield county to focus area
Pioneered multilateral success in Miss
Initiated redevelopment of Chester & Woodford
Prepared infrastructure monetization (S1’d SWG)
TOTAL SD PRODUCTION
Q4’14 ACTIVITY
•
•
•
•
•
76.1 MBoepd in Mid-Continent
121 New Midcon laterals delivered 378 Boepd 30-day IPs
10 New Chester wells delivered 470 Boepd 30-day IPs (59% oil)
3 New Woodford wells delivered 397 Boepd 30-day IPs (77% oil)
Permian Royalty Trust drilling completed
* Excludes production related to divested GOM assets.
YEAR END PROVED RESERVES +37% TO 516 MMBOE
Consistent Growth of a Strong Reserves Base
•
•
•
•
•
$5.5B SEC PV-10(a) (+34% YOY)
$10.69 Proven Value/Boe(a)
604% All-in Reserve Replacement
65% Proved Developed
All-in F&D $9.00/Boe
• 42% Liquids Mix
• 18.7 Years Reserve Life
• 12.2 Years Proved Developed
Reserve Life
• $3.04B PV-10(b) at Strip
RESERVES MIX
RESERVES GROWTH
Note: SandRidge consolidated reserves as of YE 2014 including royalty trusts
(a) Based on YE 2014 SEC pricing ($91.48/4.35)
(b) 5.1.15 Strip Pricing
CONSISTENT WELL PERFORMANCE ABOVE TYPE CURVE
Several Quarters of Stronger Gas IPs and Early Volumes
*as of 5.6.15
2015 MISSISSIPPIAN PUD TYPE CURVE
484 MBoe, 44% Liquids
2015 OIL: 118 MBo
30 Day IP (Bo/d)
1st Year Decline(a)
B Factor
190
80%
1.26
2015 NGL: 97 MBbls
Yield (Bbls/MMcf)
Shrink
51.6
86.1%
2015 GAS: 1.6 Bcf
MBoe
30 Day IP(b) (Mcf/d)
1st Year Decline(a)
B Factor
966
62%
2.00
ON TRACK TO ACHIEVE $2.4MM PER LATERAL COSTS
$350K of $600K Targeted Savings Realized as of April 2015
$130K REALIZED - EFFICIENCY GAINS
• Rig efficiency & location high-grading
• Wellbore & completion design
– Liner tool elimination
– Stimulation revision
$200K REALIZED - SERVICE COSTS
•
•
•
•
•
Liner packer system
Stimulation
Directional drilling
ESP/Artificial lift equipment
Fuel
$20K REALIZED - MULTILATERAL EXPANSION
40% MULTILATERALS IN 2015 DRILLING PLAN
106% of 90-Day Type Curve Production for
85% of the Cost of a Single Lateral*
ACTIVITY AND SUCCESS THROUGH Q1’15
• Sole multilateral operator in the Midcontinent
• Multilateral program consists of 43 projects with 2014
average completed well costs of $2.6MM per lateral with
recent Q1’15 results averaging $2.5MM per lateral
• Wells with greater than three months of production average
106% of the 90-day type curve Boe
– 105% of 90-day type curve oil
– 106% of 90-day type curve gas
DRIVING CAPITAL EFFICIENCY
• Two or more laterals from a single vertical wellbore create
significant cost reductions, yielding enhanced returns
• Rock integrity of our carbonates (vs shales or sandstones
elsewhere) allows for effective use of open hole completions
• Shared pad drilling operations drive reductions in location, day
rate, rig mobilization, & facility costs
*Single lateral well costs as of 12.31.14
FULL SECTION DEVELOPMENT
RIG ACTIVITY TARGET ACHIEVED IN FIRST HALF 2015
Current 6 Development Rigs + 1 Committed to Appraisal New Ventures
DRILLING LOCATION INFORMATION
MISS
CHESTER
WOODFORD*
Producing Laterals
1,463
41
8
1Q‘15 30-day Boe
405
452
199
3,212
401
147
(as of April 2015)
(a)
Future Locations
* Wells developed under new geological model
(a) PUDs + Risked Probables @ 5.1.15 Strip
LARGE MIDCONTINENT FAIRWAY FOR APPRAISAL
Material Success in Chester and Woodford
• Appraisal / New Ventures is a critical piece of SD business
• Focused on redevelopment of additional legacy vertical
reservoirs and technology transfer of SD expertise from
existing to new areas
• $46MM CAPEX budget in 2015 (of $700MM total) in D&C,
land, and geophysical
– Arkoma Shelf
– Central Kansas Uplift (Miss HZ, Viola, & Arbuckle)
– Southern Anadarko (Latigo and Chester Targets)
– Other recompletions and legacy acreage appraisal
NEW VENTURES SUCCESS CASE
Pioneering Chester Oil Development
• First industry horizontal re-development of legacy
Chester vertical production
– Fine grained silty sandstone, distinct pay intervals
separated by shale
– Existing infrastructure in area
– Higher oil cut and less water production than Miss
carbonates
– Shallow decline profile
• Growth potential with appraisal success to the south
and west of focus area counties
• 230-270 MBoe EUR per well
• Program: 41 wells @ 381 Boepd 30-day IP (60% oil),
109% of new Miss Type Curve
LEGACY CHESTER VERTICAL PRODUCTION
HZ APPRAISAL SUCCESS
FOCUS AREA
GEOLOGICAL EXPERTISE UNLOCKS WOODFORD
Refined Geological Model Yielding Strong Results
• Woodford targets now identified based on four
desirable characteristics:
– Production interval above Woodford
(example: Mississippian)
– Siliceous Woodford member with moveable oil
– Productive interval below Woodford
(example: Hunton or Misener)
– Underlying frac barrier separating the Woodford
from wet intervals below (example: Sylvan)
• 250-275 MBoe EUR per well
• ~100 feet of targeted gross thickness
• Program: 8 Wells @ 336 Boepd 30-day IP (79% Oil),
96% of new Miss Type Curve
Figure adapted from Amsden and Klapper (1972)
SALTWATER GATHERING & DISPOSAL (SWG)
Most Efficient SWG Operator in the Mid-Continent
PRODUCE
~$600MM INVESTED THROUGH Q1’15
• Average capacity of 15,000 Bwpd per
well
• Over 1.2 million barrels of water gathered and disposed per
day during Q1‘15 in the Mid-Continent and Permian Basin
– Low pressure pumps at most locations
GATHER & PROCESS
– Various tubing sizes based on needed
capacity
• Produced water is transported to disposal location through
SD owned pipeline system
– Open hole Arbuckle completion
• Pressure and volume continuously
monitored
• Typically Polyethylene pipe (8” to 12” diameter) connected
to producing wells, buried under ground
• Water is treated at disposal location
• > 200 SWG wells in Mid-Continent and Permian Basin
99%
• Many take water on a vacuum (hydrostatic pressure is
adequate to achieve disposal)
IS PIPED
INJECT
OF WATER
(VS. TRUCKED)
• Arbuckle has been taking produced
water for ~80 years
• Frac flowback is 1% of total
• Gathering system is interconnected –
maximizing system flexibility
LARGEST SALTWATER GATHERING SYSTEM IN THE NATION
Pipeline Footprint Resembles Typical Gathering System
• > 200 SWG wells
• Over 1.2 MMBwpd current volumes
• 99% of Water is Piped vs. Trucked
•
1,050 miles of installed pipelines
• Advanced hydraulic simulation
• Resembles hydrocarbon gathering
and processing system
• Design based on actual type curves
• Engineered design and construction
• New assets, built since 2008
100 MILES
Note: Map does not show other SWG assets in NW Kansas or West Texas.
2015 PRODUCTION GUIDANCE
Note: Totals may not foot due to rounding
(a) 2014: 1.3 MMBoe of non-recurring production related to divested GOM assets
CAPITAL STRUCTURE OVERVIEW
Preferred Stock ($ in millions)
Senior Notes ($ in millions)
8.75% Sr Notes due 2020
$450
7.5% Sr Notes due 2021
1,175
8.5% Convertible Perpetual Preferred (a)
7.0% Convertible Perpetual Preferred (b)
$265
300
$565
8.125% Sr Notes due 2022
750
Total
7.5% Sr Notes due 2023
825
Credit Rating
Moody’s
S&P
Total
$3,200
Corp Rating
B3
B
Outlook
Negative
Negative
(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) $175MM drawn as of March 31, 2015
HEDGING OVERVIEW
LIQUIDS
Q1 2015
Q2 2015
Q3 2015
Q4 2015
2015
2016
2.29
$92.71
1.73
$91.55
1.01
$92.43
0.55
$94.11
5.59
$92.44
1.46
$88.36
0.72
$103.13
$90.82
$73.13
0.73
$103.13
$90.82
$73.13
1.56
$103.65
$90.03
$78.15
1.56
$103.65
$90.03
$78.15
4.58
$103.48
$90.28
$76.56
2.56
$100.85
$90.00
$83.14
Q1 2015
Q2 2015
Q3 2015
Q4 2015
2015
2016
14.40
$4.62
1.82
$4.20
1.84
$4.20
1.84
$4.20
19.90
$4.51
0.00
NA
0.25
$8.55
$4.00
0.25
$8.55
$4.00
0.25
$8.55
$4.00
0.25
$8.55
$4.00
1.01
$8.55
$4.00
0.00
NA
NA
9.65
($0.291)
15.47
($0.302)
15.64
($0.302)
15.64
($0.302)
56.40
($0.300)
11.0
($0.380)
Swaps
Volumes (MMBbls)
Price ($/Bbl)
Three-way Collars
Volumes (MMBbls)
Call Price ($/Bbl)
Put Price ($/Bbl)
Short Put Price ($/Bbl)
NATURAL GAS
Swaps
Volumes (Bcf)
Price ($/Mcf)
Collars
Volumes (Bcf)
Call Price ($/Mcf)
Put Price ($/Mcf)
Basis Swaps (PEPL)
Volumes (Bcf)
Swap Price ($/Mcf)
• As of 5.6.15 to include 2016 basis swaps
2014 YEAR END RESERVES
Creating Value from a Strong Reserve Base
SEC Pricing $91.48 / $4.35
RESERVES
LIQUIDS
MMBbls
GAS
Bcf
PV10
PV-10
EQUIVALENT
MMBoe
%
$MM
%
Reserves by Reservoir Status
PDP – Producing
119
1,011
287
56%
15
117
35
PBP – Behind Pipe
2
76
PUD – Undeveloped
82
PNP – Non Producing
Total
$
3,523
64%
7%
462
8%
14
2%
94
2%
585
179
35%
1,437
26%
218
1,788
516
136
1,203
336
65%
82
585
179
35%
218
1,788
516
$ 5,516
Reserves by Development
Total Developed
Total Undeveloped
Total
Note: Totals may not foot due to rounding
$
4,079
74%
1,437
26%
$ 5,516
UPDATED 2015 OPERATIONAL GUIDANCE
PRODUCTION
Oil (MMBbls)
Natural Gas Liquids (MMBbls)
Total Liquids (MMBbls)
Natural Gas (Bcf)
Total (MMBoe)
CAPITAL EXPENDITURES ($ in millions)
Exploration and Production
Land and Geophysical
Total Exploration and Production
Oil Field Services
Electrical/Midstream
General Corporate
Total Capital Expenditures (excl. A&D)
EBITDA from Oilfield Services
and Other ($MM)(a)
Adjusted Net Income
Attributable to NCI ($MM)(b)
Adjusted EBITDA
Attributable to NCI ($MM)(c)
PRICE REALIZATIONS
9.0 – 10.0
4.0 – 5.0
13.0 – 15.0
89.5 – 93.5
28.0 – 30.5
$612
38
$650
5
30
15
$700
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*
11.50 – 13.50
DD&A – other
2.00 – 2.20
Total DD&A*
$13.50 - $15.70
G&A – cash
3.00 – 3.50
G&A – stock
0.50 – 0.75
Total G&A
$3.50 - $4.25
Corporate Tax Rate
Deferral Rate
0%
0%
$10
$60
$90
* Updated DD&A projection in conjunction with Q1 ceiling test
write-down. Previous range was $12.00-15.00 for DD&A Oil & Gas and $14.00-17.20 for Total DD&A
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.
2015 CAPEX GUIDANCE
2015 CAPEX GUIDANCE
Development D&C
Appraisal & New Ventures D&C
Carryover
Total D&C
SWG - D&C
Permian
JV Carry
Total D&C
2015 GUIDANCE
$306
29
102
$437
11
0
0
$448
OTHER E&P
Development Land & Geophysical
Appraisal & New Ventures Land & Geophysical
Total Land & Geophysical
SWG Infrastructure
Workovers & Non-Op
Capitalized G&A and Interest
Total Other E&P
$21
17
38
27
86
51
$202
NON E&P
Drilling & Oil Field Services
Midstream and Electrical
General Corporate
Total Non-E&P
TOTAL
$5
30
15
$50
$700
LATERAL COUNTS
Development
Appraisal & New Ventures
Total Laterals
2015 GROSS
182
11
193
2015 NET
116
8
124
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.
SANDRIDGE INVESTOR RELATIONS
123 Robert S. Kerr Avenue, Oklahoma City, OK 73102
investors@sandridgeenergy.com
www.SandRidgeEnergy.com