the latest presentation - Investor Relations

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Thursday, January 8, 2015
1
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 future operations, development plans and
appraisal programs, drilling inventory and locations, reserves, acreage positions, corporate strategies, rates of return, projected capital expenditures and other
costs, liquidity, debt maturities, 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.
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.
www.SandRidgeEnergy.com
2 2
SANDRIDGE MISSION
Premier 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.
3 3
SANDRIDGE COMPANY OVERVIEW
SD Quick Facts
• Fractured Carbonate Focus
• Mid-Continent, Horizontal
Mississippian Leader
Focus Area Asset Map
MARKET VALUE ($ in millions)
Market Cap (1/5/2015)
$742
Net Debt(a)
2,605
Preferred Stock
Enterprise Value
565
$3,912
• Sub-$3.0MM/well, 380 MBoe EUR
ASSET OVERVIEW(b)(c)
• Stacked Pay Development
Q3’14 Production (MBoe/d)
79.7
• 2014 Capex Plan of $1.55Bln
Proved Reserves (MMBoe)
377
• $590MM Cash at Q3’14
% Reserves as Liquids
46%
YE13 PV10 Value ($Bln)(d)
$4.1
a) Non-GAAP financial measure. Refer to the Disclaimer slide for additional
disclosure
b) Pro Forma for the Q1’14 Gulf of Mexico divestiture
c) SandRidge consolidated reserves as of YE2013 including royalty trusts
d) Based on YE13 SEC pricing ($93.42/$3.67)
4 4
LOWER PRICES INFLUENCE 2015
Activity, Tactics, and Costs
FOCUSED
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
5 5
SCALE &
OPERATION
FOCUS
SANDRIDGE ENERGY
Scale, 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
6 6
SANDRIDGE ENERGY
Midcontinent Scale, Capability and Upside
STRATEGY &
ASSET OVERVIEW
• 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)
7 7
GROWTH PLATFORM WITH UPSIDES
FOCUSED
Significant Acreage Position
Stacked Oily Pay Zones
Improving Already Strong Returns
8 8
MATERIAL WELL COST AND LOE REDUCTION
Mississippian Leader
FOCUSED
• 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, Trilaterals
and Full Section Development
– Wellsite facilities design improvements:
– Centralized tank batteries
– Commingled tank batteries
– Centralized Salt Water Disposal (SWD) systems
9
9
WELL COSTS CONTINUE TO IMPROVE
Plan $2.8mm For 2015 and Lower In 2016 FOCUSED
• 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
10
10
TARGETING BREAKOUT ECONOMICS
Ahead 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
11 11
2014 MISSISSIPPIAN PUD TYPE CURVE Actual Performance Consistently Above Type Curve
FOCUSED
Oil: 118 MBo
30 Day IP (Bo/day)
1st Year Decline(a)
B Factor
176
80%
1.41
NGL: 64 MBbls
Yield (Bbls/MMcf)
Shrink
47.5
87.3%
GAS: 1.2 Bcf
30 Day IP(b) (Mcf/day)
1st Year Decline(a)
B Factor
848
65%
1.83
a) Represents decline from month 1 to month 13
b) Wet gas, wellhead volumes
As of 12/10/2014
12 12
MISSISSIPPIAN WELL PERFORMANCE
Continued Improvement
MULTI-YEAR
GROWTH
Type Curve
849 Mcf/d
Type Curve
176 Bbl/d
13 13
MID‐CONTINENT FOCUS AREA Deep Understanding of the Play
FOCUSED
~650,000 Acres in Focus Area
• 3D Required to Define Fracture Trends
• Positive Multi Lateral Results
• Highest 30 Day Gas IPs
• Low H2O Cut
• Upside as Gas Prices Rise
• Chester Delivering Above
TC Oil Rates
• Multi Laterals Decreasing
per Lateral CAPEX
• High Density Fracs
Potentially Impactful
• Shallowest Decline Profile
• Higher EUR Distribution
• Geology Most
Understood
• Stacked Pay Potential
100 MILES
•
•
•
•
•
Highest 30 Day Oil IPs
Highest Liquids %
Lowest H2O Cut
Improving EURs with Time
Dual Laterals Exceeding TC
• Miss Exhibiting Tightest
Performance Distribution
• Unlocked Woodford Potential
• Potential for Extensive Multi
Lateral Development
SD LEASEHOLD
14 14
MULTI‐ZONE DRILLING LOCATIONS Many Years of Drilling Ahead
High-Graded Locations to Drill
Un-Risked Locations
Emerging
Marmaton
HZ Wells to Sales
1
development
HZ Wells to Sales
1,150
Middle Miss
35
HZ Wells to Sales
161
Lower Miss
Woodford
HZ Wells to Sales
4,510 wells
>8,000 wells
Upper Miss
Chester
HZ Wells to Sales
FOCUSED
11
HZ Wells to Sales
17
Note: Drilling location information as of 12/31/14
15 15
NEW VENTURES CASE STUDY
Chester 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 south
and west of core counties
• IP: 368 Boe/d (64% oil), 16% above Miss Type Curve
16 16
APPLYING SEISMIC TECHNOLOGY
Understanding the Rock
INNOVATION
+25% of core counties with 3d coverage
+45% of ok core counties with 3d coverage
2013 - 730 square miles of 3D data acquired
2014 - 1,070 square miles of new 3D data acquired
KS
OK
Main fault
trend
3d seismic reveals:
• Fractures
• Faulting
• Rock mechanics
• Reservoir compartments
• New plays
Parallel
fault trend
100 MILES
17 17
MULTILATERAL APPROACH IS SUCCESSFUL
Changing How Carbonates are Developed
INNOVATION
Achieving Breakthrough Cost Upsides with Production Uplift
Dual Stacked Lateral
•
Multilateral success achieved on three dual stacked laterals and one coplanar 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
•
Co-Planar Dual Lateral
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)
18 18
INNOVATION / UPSIDE FSD Offers Up to 34% More Section for 26% less capex
INNOVATION
Full Section Development
• Fracture stimulates 34% more interval: 22,000’ vs typically 16,400’ with four single
laterals
Full Section Development
• 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):
Full Section Development D&C Cost Savings Detail
Tank Battery, SWD, Powerline and Connection
Intermediate 7" Casing and ESP Savings (One Each vs Four)
Drilling Location, Rig Move and Reduced Drilling Days
Rentals and Miscellaneous
Incremental cost to frac an additional ~6000’ of interval
Total Savings
$M
$ 1,350
$ 1,100
$ 1,000
$ 350
$ (600)
$3,200
(For Illustrative Purposes)
* Strip as of 8/1/14
19 19
FULL SECTION DEVELOPMENT CASE STUDY
$2.1 MM Per Lateral, Over 4x Type Curve From 4 Laterals
INNOVATION
Kirkpatrick Farms: First FSD Well, $8.32MM Well Cost
Peak 30-Day IP: 1,086 Boe/d (60% Oil)
• 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 lateral
leading to target change in #2
– Completed and online 9/24
10,000
Water
20
20
SALTWATER GATHERING & DISPOSAL (SWG)
UPSIDES
Produced Water Gathered and Sequestered into
Arbuckle Through Cost Effective Infrastructure
Most Efficient
SWG Operator in
the midcontinent
• 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
– Many take water on a vacuum (hydrostatic
pressure is adequate to achieve disposal)
• Estimate ~$600MM invested by the end of 2014
–
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
• Inject
– + 180 disposal wells as of mid-2014,
adding ~50 wells per year
Average capacity of 15,000
BWPD per well
21 21
22
Q3’14 – CONTINUED STRONG WELL RESULTS
APPENDIX
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
23 23
2014 PRODUCTION GUIDANCE UPDATE
APPENDIX
(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)
24 24
CREDIT PROFILE
Ability to Maintain Adequate Liquidity, Reasonable Leverage
APPENDIX
• ~$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
• Contains Non-GAAP financial measures
a)
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 credit
c)
Revolver is expandable to $1.2B with written request
25 25
CAPITAL STRUCTURE OVERVIEW
APPENDIX
No Principle Currently Due until 2020
Preferred Stock ($ in millions)
Senior Notes ($ in millions)
8.75% Sr Notes due 2020
Total
$445
8.5% Convertible Perpetual Preferred (a)
1,179
7.0% Convertible Perpetual Preferred (b)
$265
300
750
Total
821
Credit Rating Corp Rating Outlook
Moody’s B1 Stable
Credit
Corp
Rating
Outlook
S&P Rating
B Stable
$3,195
$565
(c)
(c)
(a) Convertible at holder’s option at $8.0125 per common share; convertible after Feb 20, 2014 (b) Convertible at holder’s option at $7.7645 per common share; convertible after Nov 20, 2015
(c) Weighted Average Maturity excludes Credit Facility amounts
26 26
APPENDIX
HEDGING OVERVIEW
Liquids
Q1 2015
Q2 2015
Swaps
Volumes (MMBbls)
Price ($/Bbl)
2.29
$92.71
1.73
$91.55
Three-way Collars
Volumes (MMBbls)
Call Price ($/Bbl)
Put Price ($/Bbl)
Short Put Price ($/Bbl)
0.72
$103.13
$90.82
$73.13
Natural Gas
Q3 2015
Q4 2015
2015
2016
$92.43
0.55
$94.11
5.59
$92.44
1.46
$88.36
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
$83.13
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
5.40
($0.273)
5.46
($0.273)
5.52
($0.273)
5.52
($0.273)
21.90
($0.273)
0.00
NA
To be updated
1.01
Swaps
Volumes (Bcf)
Price ($/Mcf)
Collars
Volumes (Bcf)
Call Price ($/Mcf)
Put Price ($/Mcf)
Basis Swaps (PEPL)
Volumes (Bcf)
Swap Price ($/Mcf)
• 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
27 27
2013 RESERVE METRICS
Focused on the Mississippian Play
APPENDIX
Pro Forma 2013 Excluding Gulf of Mexico Proved Reserves*
SEC Pricing - $93.42 / $3.67
434%
Reserve Replacement
63%
Proved Developed
RESERVES
Liquids
MMBbls
PNP - Non Producing
25%
Reserve Growth
$10.19
Organic Drilling F&D
Total
$11.72
All-In F&D
Reserves by Development
Years of R/P Life
PV10
Equivalent
MMBoe
%
$MM
%
Reserves by Reservoir Status
PDP - Producing
16.7
Gas
Bcf
PBP - Behind Pipe
PUD - Undeveloped
88
708
206
55%
$ 2,441
59%
9
57
19
5%
283
7%
14
4%
73
2%
37%
1,306
32%
1
74
74
384
138
173
1,223
377
Total Developed
98
839
238
63%
2,797
68%
Total Undeveloped
74
384
138
37%
1,306
32%
173
1,223
377
Total
$ 4,103
$ 4,103
* Adjusted for Permian & Gulf of Mexico divestitures
• Includes non-controlling royalty trust interests
28 28
2014 MISSISSIPPIAN PUD TYPE CURVE 380 MBoe, 48% Liquids
176
80%
1.41
180
300
GAS: 1.2 Bcf
(b)
30 Day IP (Mcf/day)
1st Year Decline(a)
B Factor
848
65%
1.83
Avg. Boe/d
250
47.5
87.3%
140
120
200
Type Curve EUR
YE2013
Oil (Mbo)
NGLs (MBbls)
Liquids (MBbls)
Gas - Shrunk (MMcf)
150
118
64
182
1,185
MBoe
100
100
80
Cumulative Production (Mboe)
160
NGL: 64 MBbls
Yield (Bbls/MMcf)
Shrink
200
350
Oil: 118 MBo
30 Day IP (Bo/day)
1st Year Decline(a)
B Factor
APPENDIX
380
Mcf Shrink
NGL Yield (Bbls/MMcf)
60
87.3%
47.5
40
50
20
-
0
a) Represents decline from month 1 to month 13
b) Wet gas, wellhead volumes
1
2
3
4
5
6
7
8
9
10
Years
Type Curve Daily Avg. Rate
Type Curve Cum Production
As of 12/10/2014
29 29
APPENDIX
2014 OPERATIONAL GUIDANCE UPDATE
a)
PRODUCTION
PRICE REALIZATIONS
Oil (MMBbls)
Natural Gas Liquids (MMBbls)
Total Liquids (MMBbls)
Natural Gas (Bcf)
Total (MMBoe)
CAPITAL EXPENDITURES
10.8 - 11.2
3.6 - 3.7
14.4 - 14.9
83.5 - 84.8
28.3 - 29.0
($ in millions)
Exploration and Production
Land and Seismic
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)
$1,275
170
$1,445
15
40
50
$1,550
$30
$110
$145
Oil (differential below WTI)
NGLs (realized % of WTI)
Gas (differential below Henry Hub)
$2.60
36%
$0.65
COSTS PER BOE
Lifting
Production Taxes
DD&A – oil & gas
DD&A – other
Total DD&A
G&A – cash
G&A – stock
Total G&A
Corporate Tax Rate
Deferral Rate
$11.15 - $13.15
1.10 - 1.20
15.00 - 16.75
2.10 - 2.30
$17.10 - $19.05
3.35 – 3.55
0.60 - 0.70
$3.95 - $4.25
0%
0%
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 nonGAAP 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
30 30
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
31

the latest presentation - Investor Relations

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