credit suisse 3rd annual shale revolution symposium

Utica Shale Presentation– 5/11/2015 1

LEADERSHIP PERFORMANCE

VALUE CREDIT SUISSE

3RD ANNUAL SHALE REVOLUTION SYMPOSIUM

UTICA SHALE PRESENTATION

MAY 11, 2015

FORWARD-LOOKING STATEMENTS

Utica Shale Presentation – 5/11/2015 2

• This presentation includes "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, assumptions regarding future natural gas and liquids prices, planned drilling activity, anticipated asset sales and related adjustments, reductions in leverage, estimates of future capital expenditures, estimates of recoverable resources, projected rates of return and expected efficiency gains, as well as projected cash flow, inventory levels and capital efficiency, business strategy and other plans and objectives for future operations. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

• Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include: the volatility of oil, natural gas and NGL prices; write-downs of our oil and natural gas carrying values due to declines in prices; the availability of operating cash flow and other funds to finance reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; the limitations our level of indebtedness may have on our financial flexibility; charges incurred in response to market conditions and in connection with actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event.

• Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These estimates and underlying market prices are subject to significant volatility. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. References to “EUR” (estimated ultimate recovery) and “resources” include estimates of quantities of natural gas, oil and NGL we believe will ultimately be produced, but that are not yet classified as “proved reserves,” as defined in SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by Chesapeake. We believe our estimates of unproved resources are reasonable, but our estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

• We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law.

UTICA A DIVERSITY OF VALUE CREATION OPPORTUNITIES

(1) Assumes strip pricing as of April 21st, 2015 (2) Q1 ’15 daily average net production (3) As of March 31st, 2015


Over 1 Million Net Acres in Play

Core Acreage Potential Locations at Strip Pricing(1)

236,000+ net acres in Wet Gas Window – 1,570 potential locations 300,000+ net acres in Dry Window – 1,050 potential locations 80,000+ net acres in the Oil Window – 500 potential locations

Drilled 653

Producing 497

WOC/WOP 156

Operated Locations(3)

CHK Operated CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Potential Locations 3,120(1)

10%

27%

63%

Product Mix(2)

Oil Natural Gas Liquids Natural Gas

UTICA INDUSTRY LEADING PERFORMANCE


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Average Well Cost

Most efficient driller by 40% Based on IHS Supply Analytics – November 2014 Report

UTICA CONTINUOUS IMPROVEMENT


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14 13

2013 2014 2015E

Spud to RR (days)

$6.7 $7.2

$8.2

2013 2014 2015E

Well Cost ($MM)

5,150

6,200

7,900

2013 2014 2015E

Lateral Length (ft)

$1,300

$1,160

$1,040

2013 2014 2015E

Well Cost per ft lateral ($/ft)

$1.97

$1.16 $1.18

2013 2014 2015E

Net LOE ($/boe)

39%

16%

Winter 13-14 Winter 14-15

Winter Downtime (% Hours)

Net LOE 41% Decrease YOY ‘13 to ‘14 2% Increase YOY ‘14 to ‘15E

Winter Downtime 60% Decrease Winter over Winter

UTICA ENHANCED COMPLETIONS PROGRESS

(1) Type curve represents core wet development area


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2014 Program Daily Avg. Rate2015 Program Daily Avg. Rate2014 Program Cumulative Production2015 Program Cumulative Production

• 20% EUR improvement driven by enhanced completions

˃ Longer lateral lengths

˃ Increased stages per well

˃ Tailored cluster spacing 4,900 ft. 5,150 ft. 6,200 ft. 7,900 ft.

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2012 2013 2014 2015E

Lateral Length per Well

Stages per Well

Completion Performance

Type Curve (1) >25% Expected increase in lateral lengths vs. 2014

Eight stages per day Current average stages per day per crew; 12 stages max by single crew

UTICA REINVESTING IN CHESAPEAKE’S VALUE CREATION MACHINE


Drilling Program Avg Well Cost ($MM)

10% Well Cost Decrease 2013 Base Well to 2015E

53% LL Increase 2013 to 2015E

(1) Completion Reinvestment Started Q3 ‘14

$6.7 $6.2 $6.0

$0.3 $1.1

$0.7

$1.1

2013 2014 2015E

2013 Base Well Lateral Length (LL) Increase Completion Reinvestment

6,200’ LL 7,900’ LL

(1)

2013 Base Well @ 5,400’ LL & Previous Frac

Design

$6.7

$7.2

$8.2

5,150’ LL

UTICA TECHNICAL EXCELLENCE TAILORED FIELD DEVELOPMENT


• Leveraging >600 square miles of 3D seismic and >5,300 feet of core to optimize development

• Redefining targeting to yield 15% higher EUR/ft

• Adjusting well spacing to optimize field recovery

• Analysis utilizes the largest amount of production data in the play

~800 locations Incremental locations added vs. original 1,000’ spacing

500’ Well Spacing

700’ Well Spacing

1,000’ Well Spacing


UTICA TECHNICAL EXCELLENCE CUSTOMIZED CLUSTER SPACING


• Completion customized to reservoir and maturity

• Evolution driven by rigorous core analysis and supported by extensive field testing

• Reduced cluster spacing in east (implemented early 2014)

• Ultra reduced cluster spacing in west (implemented mid-year 2014)

~25% Increase in EUR Ultra Reduced Cluster Spacing

~50% Increase in IP rates Ultra Reduced Cluster Spacing

Ultra Reduced Cluster Spacing

Reduced Cluster Spacing


THE RESULT: A UTICA NAV THAT IS STRONG AND GROWING


$7.1 – $8.9 Billion Utica NAV at PV10 & Strip Price

PV10 at Strip Price as of April 21st, 2015

$8,470

$4,160

$1,970

$780 $7,060

$420 $480

$960 $8,920

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

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NAV

$M

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Wet / Dry LL Old: 6,500’ / 7,500’ New: 8,000’ / 10,000’

UPSIDE

UTICA WET GAS WINDOW A PROVEN PERFORMER

Strip Price as of April 21st, 2015 mboe values assume ethane ‘must recover’


NW Wet Type Curve

• 1,150 mboe EUR • 3.5 bcf

• 330 mbo

• 8,000’ LL / $7.9MM

• 370 Potential Locations

SW Wet Type Curve

• 1,500 mboe EUR • 4.7 bcf

• 440 mbo

• 8,000’ LL / $7.9MM


NE Wet Type Curve

• 1,450 mboe EUR • 6.3 bcf

• 70 mbo

• 8,000’ LL / $5.9MM


SE Wet Type Curve

• 2600 mboe EUR • 12.7 bcf

• 40 mbo

• 8,000’ LL / $6.0MM



UTICA WET GAS WINDOW CONFIDENCE IN WELL RESULTS

Chart production is normalized to type curve lateral lengths of 8,000


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Oil

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Southwest Wet Gas

• 24-hr production results from Ultra Reduced Cluster Spacing

• 702 bo / 5.0 mmcf • Poinsettia 36-12-5 1H / 5,800’ lateral

• 634 bo / 3.4 mmcf • Yoder 33-12-5 8H / 7,300’ lateral

Southeast Wet Gas

Northeast Wet Gas Northwest Wet Gas

Type Curve Gas Avg Results Oil Avg Results

UTICA IMPROVING PERFORMANCE LEADS TO CORE EXPANSION


~25% Expected rate of return based on actual results(1)

• Optimized completions

• Enhanced geologic interpretation

˃ Targeting

˃ Fault identification

˃ Pressure mapping

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Columbiana County Well Results

Early WellsNew WellsExpected Type Curve

+50% Improvement in new well performance vs. early wells

CHK/TOT JV Outline CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

3 Wells

9 Wells

(1) Recent Columbiana County results based on flat pricing of $65/bbl for oil and $3.25/mcf for gas

UTICA BASE OPTIMIZATION


• Operating more efficiently

˃ Decreasing downtime through better winter operations preparation

˃ Choke management

˃ Pressure maintenance program

• Midstream improvements

˃ Line pressure decrease

˃ Fewer disruptions

2015 Base Gross Operated Production

60% Reduction in winter downtime 2014 – 15 vs. 2013 – 14

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Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 -

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Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15

UTICA DRY GAS DEVELOPING THE PORTFOLIO

Several vintage Chesapeake peak rates based on old frac designs during initial acreage capture


7.1 mmcf/d

5.9 mmcf/d

6.9 mmcf/d

14.7 mmcf/d

12.7 mmcf/d

17.7 mmcf/d

8.6 mmcf/d

18.1 mmcf/d

20.5 mmcf/d

5.9 mmcf/d

30.0 mmcf/d

32.5 mmcf/d

22.5 mmcf/d

14 mmcf/d

8.8 mmcf/d

59 mmcf/d

25 mmcf/d

29.4 mmcf/d


• 1,050+ potential locations

• Planning 9,000’-10,000’ laterals

• Expect 11-18 bcf EUR’s

• 18 wells online by Q2 2016

300,000 acres Net dry gas acres in Jefferson, Columbiana County, OH and Beaver County, PA

UTICA OIL WINDOW EXTENDING THE BOUNDARY OF OPPORTUNITY


Oil Window Test Area

Parker 3H

1.3 mmcf/d 770 bo/d

Carrizo

1.1 mmcf/d 502 bo/d

EV Nettles


• Leveraging proprietary Reservoir Technology Center (RTC)

• Optimizing lateral placement

• Modifying fluid chemistry, volumes, and frac geometries

• Parker 101H - Butane Frac

• 3 additional oil window tests completed by YE 2015

770 bo / 1.3 mmcf Parker 3H Peak 24-hr production (1st sales June 2014)

80,000 net acres High-Graded Oil Window Acreage 500+ locations

UTICA PROCESSING AND FIRM TRANSPORTATION ADVANTAGES

FT volumes are CHK marketed volumes, processing volumes represent full train capacities


Upper Midwest & Canadian Markets

2017: 200 mmcf/d

Natrium I 200 mmcf/d

Leesville I 200 mmcf/d

Kensington I, II, III 600 mmcf/d

ATEX Ethane Line – sufficient FT to meet

must-recover volumes

Gulf Coast Markets

2015: 440 mmcf/d 2016: 732 mmcf/d

Highlights: • Excellent flexibility with

gathering/processing system • 99.7% runtime on majority of system • Access to premier residue gas markets

TETCO OPEN Advantage (350 mmcf/d) • Early mover advantage provides for lower FT

rate • Strategically located through CHK acreage

position

UTICA 2015 FIRM TRANSPORTATION BREAKDOWN


• First mover advantage ˃ Lower rates and larger exposure to premium

Gulf Coast Markets

• Increasing Basin Takeaway Capacity ˃ Opportunity to acquire potentially

underutilized capacity

• Nexus Advantage ˃ Transport to Dawn and create incremental

demand

$- $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 $0.45 $0.50

CHK A B C D ECompany

Leading Firm Transport Rates

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90%

CHK A B C D ECompany

Gulf Coast Exposure Advantage

NEXUS 200k 17-Nov Oct-32 DawnOPEN 350k 15-Nov 30-Oct Gulf

TGP BH 232k In-Service 28-Jul GulfTGP BH 50k In-Service 17-Sep Gulf

TGP MPP 99k In-Service 23-Oct GulfDTI TL-400 39k In-Service 19-Nov DTI Market

DTI Natrium to Mkt 57k In-Service 27-Dec DTI Market

Pipeline/ ProjectCHK

CapacityDelivery Location

Firm Transportat ion

Start Date End Date

UTICA NATURAL GAS LIQUIDS


• ATEX: Right-sized ethane takeaway capacity for Utica development program ˃ Minimizing excess ethane recovery

• Maximize NGL value by actively participating in NGL marketing ˃ 100% approval of where our product moves

and the associated netbacks and directly markets ~37% of NGLs

2015 2016 2017 2018

ATEX Ethane Commitment

Current Capacity Former Capacity*

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18

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Propane Butane Natural Gasoline

Days

of S

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Leading NGL Storage Capacity

27%

43%

20%

10%

Utica Barrel Composition

UTICA AN ESSENTIAL PLACE TO INVEST


ABUNDANT PROSPECTS

CONTINUOUS IMPROVEMENT

BASIN-LEADING VALUE

RESILIENCY TO VOLATILTY