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INVESTOR PRESENTATION CAUTIONARY STATEMENTS Forward Looking - - PowerPoint PPT Presentation

JANUARY 2017 INVESTOR PRESENTATION CAUTIONARY STATEMENTS 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


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SLIDE 1

INVESTOR PRESENTATION

JANUARY 2017

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SLIDE 2

CAUTIONARY STATEMENTS

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, our drilling inventory and locations, estimated production, rates of return, reserves, projected capital expenditures, projected operating, general and administrative and other costs, anticipated efficiency and cost reduction initiative outcomes, the acquisition of seismic data, infrastructure utilization and investment, liquidity, capital structure, hedging position and strategies, and price realizations and differentials. 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

  • f 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 10-K for the year ended December 31, 2015 and in comparable “Risk Factors” sections of our Quarterly Reports on Form 10-Q filed after such Form 10-K. 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 terms "EUR" (estimated ultimate recovery) and “recoverable reserves” 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 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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Forward Looking Statement

www.sandridgeenergy.com

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SLIDE 3

SANDRIDGE ENERGY

With a strong balance sheet, we have competitive project IRRs from the high-graded harvest of our Mid-Continent position, plus we’re adding portfolio diversification and long term growth from our North Park Niobrara project, with capacity to do more.

3 www.sandridgeenergy.com

  • Over $500MM of Liquidity
  • Moderate Level of

Outspend

  • Protect the Balance Sheet
  • Long Runway
  • High-Graded Harvest
  • Competitive Project IRRs
  • Adjacent Zone Drilling

(Meramec/Osage)

  • Continue to Drive Down

Costs

  • Produce Consistent Well

Results

  • Innovate on Well Designs
  • Dominant North Park

Position

  • Long Term Oil Growth
  • Expands Drilling

Inventory

  • 1,300 2P Locations
  • Additional Zones
  • Extended Reach Laterals

(“XRL”) & Multilaterals (“Multi”)

  • New Areas
  • Pioneering Technologies
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SLIDE 4

4

SANDRIDGE ENERGY OVERVIEW

UNLEVERED OIL PRODUCER FOCUSED ON RESOURCE VALUE CREATION

KEY INFORMATION

FULLY DILUTED MARKET EQUITY VALUE @ $24 / SHARE 20.6 MM Common shares + 14.8 MM Conversion shares = Estimated Market Cap $494 Million + $ 355 Million = $850 Million PRIMARY ASSETS

Mid-Continent Focus Area 458k

Net Acres

~300 2P

1

Locations

(includes prospective Meramec/Osage) (excludes prospective Meramec/Osage)

North Park Basin Niobrara Oil 133k

Net Acres

~1,300 2P

1

Locations

PRODUCTION & RESERVES

Q3’16 Production 49.6 MBoepd

2

(28% oil)

SEC Proved Reserves 281 MMBoe at YE’15

3

(25% oil)

138 MMBoe at Q3’16

~20% higher at recent strip pricing (1) 2P locations: Undeveloped Proved and Probable (2) Excludes production related to noncontrolling interests (3) SandRidge reserves and PV-10 pro forma for WTO divestiture and net of noncontrolling interests as of 12.31.15, based on SEC pricing at that time ($46.79 / $2.59)

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SLIDE 5

CREATING RESOURCE VALUE IN TWO BASINS

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  • High-graded harvest and expansion of our Mid-Continent asset
  • Q4’16 Miss XRLs reduce 2016 average D&C from $1.9MM to $1.7MM per lateral,

supporting competitive IRRs at Dec 2016 strip

  • ~1,300 producing horizontal wells, 3D seismic and improved reservoir characterization
  • One rig active most of 2016 and 2017, with Miss and Meramec/Osage focus

– Production decline moderating as 2014-15 producers mature

  • Industry leading well costs and innovative multi and XRL development
  • Drilling adjacent plays including Meramec/Osage focused counties: Garfield, Major, and Woodward
  • Industry activity moving north and west surrounding our position
  • Growth in oil reserves and anticipated value per barrel via North Park Niobrara development
  • Achievable well costs (sub-$3MM per lateral D&C in 2017) support competitive IRRs
  • 1,300 proved and probable locations with significant near term PUD potential
  • 100% XRL program in 2017
  • Upside through more Niobrara benches, completion and spacing optimization, and lower well costs
  • Net unlevered balance sheet1 and strong liquidity provides financial flexibility

– ~$536MM liquidity, ~$111MM of unrestricted cash, & undrawn $425MM revolver2

  • Sub-$200MM 2017 CAPEX plan: 1 rig for part of year in each of Mid-Continent and Niobrara
  • ~55% reduction in workforce since beginning of 2016

(1) Excluding mandatorily convertible notes (2) Pro Forma for debt pay down following emergence on 10.4.16 and excludes approximately $10MM of LOCs

HARVEST & APPRAISE

MID-CONTINENT HIGH-GRADE PLUS ADJACENT MERAMEC/OSAGE DRILLING IN THREE COUNTIES

DIVERSIFY

GROW OIL RATE AND RESERVES IN NIOBRARA

UN-LEVERED

STRONG FINANCIAL POSITION

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SLIDE 6

6

SUB-$200MM 2017 CAPEX TARGETS ATTRACTIVE IRRS

PLUS 2017 PUD ADDITIONS IN BOTH MID-CONTINENT AND NIOBRARA

  • Finish 2016’s successful high-graded Miss program

– Late 2016 Miss XRLs (4 laterals total) at <$1.5MM D&C per lateral – Drilling technology and well cost reduction focus transfer to both Meramec /Osage and Niobrara

  • Appraise and confirm Meramec/Osage potential in three counties

– Major, Garfield, and Woodward Counties – Potential for material PUD additions in 2017

  • Develop and delineate North Park Niobrara Oil resource

– Sub-$3MM D&C per lateral targeted in 2017 program (100% XRLs) – Potential for material PUD additions in 2017

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SLIDE 7

7

2017 MERAMEC/OSAGE PROGRAM IN 3 OKLAHOMA COUNTIES

POTENTIAL TO ADD MATERIAL LOCATIONS THROUGH MERAMEC/OSAGE DEVELOPMENT

  • Garfield Co: 1 Meramec well and 3

Osage wells producing in Garfield to be followed up by 1 Meramec XRL in 2017

  • Major Co: 2 drilled wells confirmed

Meramec and Osage production, to be followed up by 4 Meramec XRLs in 2017

  • Woodward Co: Test Meramec/Osage in

2017 with 1 XRL adjacent to peer production

2017 activity supports appraisal of three counties

INDUSTRY ACTIVITY ADJACENT TO SD ACREAGE INDUSTRY ACTIVITY IS CONVERGING ON EXISTING SANDRIDGE ACREAGE SD Meramec/Osage activity in 3 counties:

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SLIDE 8

8

  • SandRidge is a leading producer in the Mid-Continent
  • Stacked reservoirs on large acreage base

– Mississippian – Chester/Manning – Meramec/Osage gaining industry attention

  • Miss Lime has been primary target

– +/- 300’ thick carbonate at ~6,000’ TVD – Over 1,600 horizontal wells drilled in OK & KS since 2010

  • Salt water disposal infrastructure

– 1,095 miles of pipeline, connected to 136 active disposal wells

  • Electrical infrastructure

– 1,250 miles of power lines, six substations and two micro grids

MID-CONTINENT OVERVIEW

458K NET ACRES IN OKLAHOMA, WITH MISSISSIPPIAN, CHESTER, AND MERAMEC/OSAGE PRODUCTION

KS OK

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DURABLE IMPROVEMENT IN ECONOMICS

MULTIS AND XRLS ARE A BREAKTHROUGH IN MISSISSIPPIAN

D&C CAPEX, $MM PER LATERAL

Lower costs per lateral

  • 43% vs 2014

90-DAY CUMULATIVE MBOE PER LATERAL

Results shown by groups of 50 wells

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SLIDE 10

10

MISSISSIPPIAN RECOVERIES IMPROVING

HIGH-GRADE YIELDING TIGHTER EUR DISTRIBUTIONS WITH BETTER RESERVOIR CHARACTERIZATION

  • High-graded harvest resulting in

more consistent results

  • Remaining Mississippian

locations form reliable inventory

  • Multi and XRL costs per lateral

support competitive returns

P10 / P90 RATIO

2013 2014 2015 2016 7 8 7 2

PROJECTED EURS

NORMALIZED BY LATERAL

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SLIDE 11

$1.7MM Avg D&C per Lateral

  • 2 XRLs:

(equivalent to 4 single laterals)

  • 1 dual XRL:

(equivalent to 4 single laterals)

  • 1 full section development:

(equivalent to 3 single laterals)

  • 1 coplanar:

(equivalent to 2 single laterals)

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2016 MISSISSIPPIAN VALUE CREATION

MULTIS AND XRLS REDUCE COSTS AND PRESERVE COMPETITIVE RETURNS AT LOWER COMMODITY PRICES

(1) Estimated based on historical realized pricing + 12.19.16 NYMEX Strip and actual production + forecasted production

2016: 13 Miss laterals 51% IRR

1

100% Multi and XRL

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SLIDE 12

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  • XRLs of $7.0MM D&C Capex ($3.5MM per lateral)

with projected 600 MBoe EUR and targeting sub- $3MM per lateral in 2017

  • Eleven laterals drilled in 2016 including one XRL
  • 60 drilling permits approved
  • 28 MMBoe of proved reserves1 (81% oil); 108 PUDs
  • Federal units largely eliminate near term HBP

drilling requirements, ~75k net acres currently held by production or unit (56%)

  • Additional 33k net acres proposed to be held by

unit by year end 2017, for a total of ~108k net acres held by unit or production (81%)

NORTH PARK NIOBRARA ASSET OVERVIEW

DOMINANT ACREAGE POSITION WITH HIGH OIL CUT

(1) SandRidge reserves as of 12.31.15, based on SEC pricing ($46.79 / $2.59)

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SLIDE 13

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NIOBRARA DRILLING ECONOMICS

REDUCING COSTS $500K PER LATERAL SUPPORTS LARGE IRR UPSIDE; CURRENT COSTS ACHIEVED AFTER JUST 11 LATERALS INCLUDING ONLY 1 XRL

Assumptions: XRL $7.0MM D&C cost ($3.5MM per lateral), 600 MBoe EUR

XRL

CURRENTLY $3.5MM PER LATERAL Targeting <$3.0MM per lateral Current $3.5MM per lateral

Reducing cost per lateral of XRLs will be a priority in 2017

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INITIALLY TARGETING LOWER NIOBRARA

SIMILAR GEOLOGIC CHARACTERISTICS TO THE DJ BASIN NIOBRARA BUT HIGHER OIL CUT

NORTH PARK BASIN DJ BASIN

Oil EUR % 81% 35% - 40% Depth 5,500 – 9,000 ft. 6,000 – 8,000 ft. Reservoir Storage Capacity Gross Thickness Porosity 450 – 480 ft. 6 – 9% 150 – 300 ft. 6 – 10% OOIP per Section 63.8 MMBo 41.3 MMBo Thermal Maturity (Ro) 0.75 – 1.0% 0.5 – 1.4+% Reservoir Production Potential Reservoir Pressure Gas-oil Ratio (GOR) Total Organic Content > 0.55 psi/ft 600 – 700 scf/stb 3% 0.41 - 0.60 psi/ft Up to 10,000+ scf/stb 3%

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2016 SANDRIDGE NIOBRARA RESULTS

478 BOEPD (90% OIL) AVERAGE 30-DAY IP ON FIRST FIVE SANDRIDGE LATERALS

DESIGNED TO TEST

  • Cycle time reduction
  • XRL
  • Additional bench
  • Spacing
  • Stimulation methods
  • Artificial lift methods

SIX LATERALS ONLINE IN LATE 2016 FIRST FIVE SANDRIDGE LATERALS Initial results of 2H’16 wells to be released with Q4’16 earnings

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SLIDE 16

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GREGORY 1-9H, 550 BOEPD (89% OIL) 30-DAY IP

FIRST SANDRIDGE NIOBRARA LATERAL

THE GREGORY 1-9H CONTINUES TO OUTPERFORM TYPE CURVE

Cumulative production

  • f 82 MBo at 250 Days
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NIOBRARA TYPE CURVE SUPPORT

AVERAGE OIL RATE OF FIRST FIVE SANDRIDGE LATERALS DRILLED

FIRST 5 SANDRIDGE LATERALS

  • Outperforming type curve
  • Free flowed for over three months
  • First three laterals currently on

artificial lift

  • Optimizing production by

accelerating artificial lift on future installations

  • Installing artificial lift on all

remaining 2016 laterals in Q1’17

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SLIDE 18

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LAST 14 LATERALS USING MODERN COMPLETION DESIGNS

14 LATERALS SUPPORTING TYPE CURVE CUMULATIVE OIL

Average Cumulative Oil 126,298 Bbls 96,917 Bbls Cumulative Type Curve Oil

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SLIDE 19

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ACHIEVABLE UPSIDE IN NIOBRARA

LOWER COSTS, OPTIMIZED COMPLETIONS, XRLS, STACKED PAY AND LOCATION COUNT

HBP AND FEDERAL UNITS HOLD 56% OF ACREAGE

UPSIDE INCLUDES

  • Successfully drilling XRLs; first 2-mile lateral drilled and

completed in Q3’16 and brought online in Q4’16

  • Proving up additional benches

– First SandRidge well, the Gregory 1-9H, producing from Upper and Lower Niobrara – Shallow Niobrara bench test well drilled in Q3’16; completed and brought online in Q4’16

  • Expanding structural and geologic reservoir

characterization model beyond existing 54 square miles of 3D seismic by acquiring additional 64 square miles of 3D seismic starting in 2017

  • Optimizing completions to enhance production rate and

ultimate recovery, while reducing costs

  • Reducing drilling and completion costs through applied

learnings and observing DJ Basin operators

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SLIDE 20

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NIOBRARA ASSET MIDSTREAM STATUS

WTI OIL DIFFERENTIAL HAS BEEN REDUCED FROM $11+/BBL TO $3.15/BBL

NORTH PARK BASIN POTENTIAL PIPELINE ROUTES

CURRENT OIL AND GAS DISPOSITION

  • Building out field gathering infrastructure; centralized

tank battery used for processing, storage and export

  • Oil trucked to market (centralized oil loading bay

could handle 40 MBopd)

  • Gas combusted under appropriate permits

MIDSTREAM STRATEGIC OPTIONS

  • Reduce air emissions by removing liquids from gas

stream with gas reinjection being considered to reduce combustion volumes

  • Oil and gas pipelines under evaluation

– Currently proceeding with engineering, permitting and right-of-way acquisition for oil and natural gas pipelines

Plains Rocky Mountain Pipeline Rockies Express Pipeline (REX) Colorado Interstate Gas Pipeline (CIG)

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SLIDE 21

APPENDIX

21

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SLIDE 22

THE REORGANIZED SANDRIDGE ENERGY AS OF OCT. 31ST

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COMMON EQUITY MANDATORILY CONVERTIBLE DEBT $425MM REVOLVING CREDIT FACILITY $111MM CASH

$536MM Liquidity

  • 20.6 MM common shares outstanding
  • 14.8 MM issuable upon conversion of mandatorily convertible debt
  • 4.9 MM warrants at $41.34 strike price
  • 2.1 MM warrants at $42.03 strike price
  • $278MM1 face value
  • Unsecured and mandatorily convertible into 14.8 MM shares
  • No interest2
  • Undrawn3
  • Minimal covenants or borrowing base redeterminations for two years
  • LIBOR (100 bps floor) + 475 bps rate
  • $111MM in unrestricted cash

(1) $3.7 million par value converted as of October 31st (2) Make-Whole applicable if note accelerated following an event of default (3) Pro Forma for debt pay down following emergence on 10.4.16 and excludes approximately $10MM of LOCs Note: In addition to the items above there is a $35MM note secured by the Company’s non-oil and gas real property

net share settled

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SLIDE 23

NEW SANDRIDGE CAPITAL STRUCTURE

23 www.sandridgeenergy.com

$536 MM OF TOTAL LIQUIDITY DE-LEVERED BALANCE SHEET

(1) Secured by mortgages on the Company's non-oil and gas real property (2) $3.7 million par value of conversions as of Oct 31st (3) Excludes approximately $10 million of letters of credit

PRO FORMA CAPITAL STRUCTURE

$MM

DEBT AT PRINCIPAL VALUE AS OF JUN 30, 2016 RESTRUCTURING PRO FORMA

AS OF OCT. 31, 2016

Secured Note1 $ - $ 35 $ 35 8.75% Second Lien Secured Notes due 2020 1,328 (1,328)

  • Unsecured Notes:

8.75% Senior Unsecured Notes due 2020 $ 396 $ (396) $ - 7.50% Senior Unsecured Notes due 2021 758 (758)

  • 8.125% Senior Unsecured Notes due 2022

528 (528)

  • 7.50% Senior Unsecured Notes due 2023

544 (544)

  • Sub-Total Unsecured Notes

$ 2,225 $ (2,225) $

  • Unsecured Convertible Notes:

8.125% Senior Unsecured Convertible Notes due 2022 $ 41 $ (41) $

  • 7.50% Senior Unsecured Convertible Notes due 2023

47 (47)

  • Total Senior Debt

$ 3,641 $ (3,606) $ 35 0.00% Mandatorily Convertible Senior Subordinated Notes2

  • 278

278 Total Debt $ 3,641 $ (3,328) $ 313

Liquidity

RBL Borrowing Base3 $ 500 $ (75) $ 425 RBL Available

  • 425

425 Cash 634 (523) 111 Total Liquidity $ 634 $ (98) $ 536

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SLIDE 24

2016 OPERATIONAL GUIDANCE

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TOTAL COMPANY PRODUCTION

Oil (MMBbls) 5.4 - 5.5 Natural Gas Liquids (MMBbls) 4.1 - 4.3 Total Liquids (MMBbls) 9.5 - 9.8 Natural Gas (Bcf) 57.0 - 57.3 Total (MMBoe) 19.0 - 19.4

PRICING REALIZATIONS

Oil (differential below WTI) $3.75 NGLs (realized % of WTI) 30% Gas (differential below Henry Hub) $0.50

COSTS PER BOE

LOE $8.80 - $9.00 DD&A – oil & gas1 5.80 - 6.20 DD&A – other 1.40 - 1.45 Total DD&A $7.20 - $7.65 G&A – cash2 $3.70 - $3.90

% OF NET REVENUE

Severance Taxes 2.00% - 2.25% Corporate Tax Rate 0% Deferral Rate 0%

(1) May be materially affected at year end by application of Fresh Start accounting (2) Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, shareholder litigation costs, restructuring costs, and other non-recurring items. Incentive compensation plan normalized to be consistent with prior year compensation plans. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. 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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2016 CAPITAL EXPENDITURES GUIDANCE

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CAPEX GUIDANCE DETAIL $MM

Mid-Continent D&C $42.5 - $47.5 North Park D&C 55 – 60 Other - D&C1 25 Total Drilling & Completing $122.5 - $132.5

OTHER E&P

Land, G&G and Seismic $10 - $15 Infrastructure2 20 – 22.5 Workovers 37.5 – 40 Capitalized G&A and Interest 25 Total Other E&P $92.5 - $102.5

NON E&P

General Corporate $5 Total Capital Expenditures (excl. A&D and P&A) $220 - $240

CAPEX GUIDANCE $MM

D&C $122.5 - $132.5 Other E&P $92.5 - $102.5 Total Exploration and Production $215 - $235 General Corporate $5 Total Capital Expenditures $220 - $240

LATERAL SPUDS GROSS NET

Mid-Continent 26 21 North Park 11 11 Total Laterals 37 32

(1) 2015 Carryover, JV Penalty, Rig Penalty, Non-Op, SWD (2) Facilities - Electrical, SWD, Gathering, Pipelines

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HEDGING OVERVIEW

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OIL

Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 Q1’18 Q2’18 Q3’18 Q4’18 FY 2018 SWAPS Volumes (MMBbls) 1.29 0.63 0.64 0.64 0.64 2.56 0.27 0.27 0.28 0.28 1.10 Price ($/Bbl) $56.45 $51.45 $51.45 $51.45 $51.45 $51.45 $55.10 $55.10 $55.10 $55.10 $55.10

NATURAL GAS

Q4’16 Q1’17 Q2’17 Q3’17 Q4’17 FY 2017 SWAPS Volumes (Bcf) 10.92 7.20 7.28 7.36 7.36 29.20 Price ($/Mcf) $2.86 $3.19 $3.19 $3.19 $3.19 $3.19 BASIS SWAPS (PEPL) Volumes (Bcf) 0.92 NA NA NA NA NA Price ($/Mcf) ($0.38) NA NA NA NA NA

Note: As of 11.08.16