Barclays CEO Energy-Power Conference

Barclays CEO Energy-Power Conference September 3, 2014

New York, NY

2 I BARCLAYS CEO ENERGY-POWER CONFERENCE – SEPTEMBER 3, 2014

• 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, estimated future capital expenditures, estimates of recoverable resources, projected rates of return and expected efficiency gains, as well as projected cash flow, 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 2013 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 27, 2014. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil 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; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; a deterioration in general economic, business or industry conditions having a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; adverse developments and losses in connection with pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and an interruption at our headquarters that adversely affects our business.

• 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 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. 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.

• The transaction with RKI is subject to closing conditions, including third-party consents, and may not be completed in the time frame anticipated or at all. Chesapeake’s interest in the properties acquired in the RKI exchange will be reduced if applicable participation rights are exercised and other conditions, including payment to Chesapeake of consideration for such participation, are fulfilled.

• 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 release, except as required by applicable law.

FORWARD-LOOKING STATEMENTS


• Balance capital expenditures with

cash flow from operations

• Divest noncore assets and

noncore affiliates

• Reduce financial and operational

risk and complexity

• Achieve investment grade metrics

• Develop world-class inventory

• Target top-quartile operating and

financial metrics

• Pursue continuous improvement

• Drive value leakage out of

operations

APPLYING OUR BUSINESS STRATEGIES


TRANSFORMING OUR BUSINESS

• Portfolio management and capital

allocation process

• Corporate budget process and plan

• Performance measurement and

compensation program

• Organizational structure

• Decision rights

• Focus on capital efficiency

• Cash cost reduction


FOUNDATIONAL ELEMENTS

FOR VALUE CREATION

CHK

• Growing production while de-levering

• Industry-leading capital efficiency

• Differential future growth


CAPITAL DISCIPLINE

$14.2

~$5.8 ~$5.8

(1) 2014 based on midpoint of company Outlook issued on 8/6/2014; capex includes capitalized interest; 2015 estimate is midpoint of preview provided at Analyst Day

$7.6

(1) (1) $ in

billio

ns


(1) CHK Production Growth and Capex based on midpoint of company Outlook issued on 8/6/2014. Total CHK Capex includes capitalized interest. Peer group in alphabetical order includes: Anadarko, Apache, Continental, Devon, EOG, Hess, Marathon, Noble, Pioneer and Southwestern. Adjusted production data includes APA, APC, CHK, DVN and MRO.

Source: Bloomberg and peer company issued guidance

DEPLOYING CAPITAL EFFICIENTLY

(1)


41 - 48 Liquids Focused Rigs

14 - 17 Natural Gas Focused Rigs

55 - 65 Total Operated Rigs

OPERATIONS UPDATE

2014E Avg. Operated Rig Count

(1) Net of Utica and PRB drilling carries; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest (2) Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays

• CHK recently increased midpoint of its expected 2014 daily production rate by 10 mboe/d

• Based on current performance and anticipated completion of infrastructure, CHK expects 2014 exit rate to exceed 730 mboe/d

• CHK plans to connect 35% more wells to sales in 2H’14 vs. 1H’14

2Q’14 Daily Avg. Net Production (mboe/d)

(2)

17-20

5-6

(2)

2014E % of Total E&P Capex by Play(1)

<5% <5%

~

~

~

~

~

40%

15%

15%

10%

10%

5%

Eagle Ford

Mid-Continent

Utica

Marcellus North

Haynesville

PRB Niobrara

Marcellus South

Barnett

~


• CHK and RKI Exploration & Production, LLC (RKI) transaction closed 8/19/2014

> +66,000 net acres and average working interest from 38% to 79%

> Consolidates position in the southern area over multiple stacked pays

• Niobrara Formation: Oil Growth on the Way, Rates of Return Rising

> 2015 oil growth engine: New gas processing plant in 4Q’14 will remove constraints

> Rates of return >40%

> Shifting from wet gas/condensate drilling to fractured black oil window in 2H’14

• Upper Cretaceous Sands Starting to Deliver

> Three successful Sussex wells to date; targeting ROR >50%

> Further testing planned on Sussex, Teapot, Parkman and Shannon formations in 2H’14

POWDER RIVER BASIN – INCREASING EXPOSURE

IN A WORLD CLASS OIL PLAY


CHK Operated

RKI Operated

POWDER RIVER BASIN –

RKI ACREAGE EXCHANGE

Pre-transaction Post-transaction

Pre-transaction Post-transaction

322,000 Net Acres 388,000

38% Avg. Working Interest 79%

10 mboe/d Net Daily Production 14.5 mboe/d

2014: 3 rigs Avg. Rig Count 2015: 7 - 9 rigs

CHK Avg. Working Interest = 38% CHK Avg. Working Interest = 79%

CHK Operated Rigs CHK Leasehold


• Gross Recoverable Resources of >2.0 bboe

> Niobrara

• ~1,500 mmboe

• 50% to 70% oil/condensate

• Estimated 45° - 60° API gravity

> Upper Cretaceous(1)

• ~325 mmboe

• >75% oil/condensate

• Estimated 40°- 48° API gravity

> Additional Potential

• Frontier ~250 mmboe

• Excludes Mowry shale (source rock) upside

SOUTHERN PRB RESOURCE POTENTIAL

(1) Upper Cretaceous Sands include Sussex, Shannon, Teapot and Parkman

72%

28%

Niobrara

Upper Cretaceous / Frontier

% Recoverable Resources by Formation


Sussex

focus

area is

~20 miles

long by

~5 miles

wide

SUCCESSFUL SUSSEX DELINEATION AND

ADDITIONAL UPPER CRETACEOUS TESTS

I

CHK Operated

RKI Operated

Sussex I •Peak 24 Hr. Rate: 1,335 bbls oil,

735 bbls NGL, 3.5 mmcf

•Cumulative prod.to date: 230 mboe

in 150 days (85% oil)

Sussex III •Peak 24 Hr. Rate: 877 bbls

oil, 35 bbls NGL, 0.5 mmcf

•Drilled in <17 days

Sussex II • Peak 24 Hr. Rate: 1,050

bbls oil, 115 bbls NGL,

1.5 mmcf

• Near-term activity

> 6 Sussex spuds in 2H’14

> 1 Parkman test 4Q’14

> 1 Teapot test 4Q’14

> 1 Shannon test 4Q’14

• Reached total depth on Sussex IV

> ~6,000 ft. lateral

• Currently drilling Sussex V

> ~9,200 ft. lateral planned

V IV

II

III

Sussex Formation


• Targeting avg. rate of return in excess of 40%

> Cycle times / drilling cost per ft. continue to decline

> Increasing lateral lengths (from 5,800 ft to 6,800 ft. on avg.)

> Enhanced completions through tighter cluster spacing and more proppant resulting in higher EUR/ft

NIOBRARA –

CONTINUOUSLY IMPROVING ECONOMICS

Cost/Ft. and Lateral Length D&C and ROR (%)

+20% EUR


HAYNESVILLE

ASSET OVERVIEW

(1) EUR represents 2014 program (2) 2Q’14 daily avg. net production

Avg. Well Costs ($ in mm)

• ~10 tcfe of net recoverable resources

• 2Q’14 avg. net production of ~508 mmcfe/d

> Up 26% YOY, adjusted for asset sales

• Averaged 8 operated rigs and connected 13

gross wells in 2Q’14

• 8.9 bcfe gross EUR per well(1)

387,000 net acres 71% avg. WI, 57% avg. NRI

Production mix(2)

<

CHK Operated Rigs

Industry Rigs

CHK Leasehold


HAYNESVILLE ECONOMICS

Rate of Return(1)

(1) Represents 2014 program. Burdened ROR scenarios assume differentials to NYMEX natural gas prices of ($1.45)/mcf for gathering/transportation costs and regional basis differential. Also assumes 180 day spud to TIL cycle time delay for a three well pad.

• Cost control measures and improving natural gas prices drive stronger returns

• ROR exceeds 100% when considering minimum volume commitment (MVC) and firm

transport (FT) as sunk costs

>100% Unburdened ROR in Haynesville


CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Oil Window Test Area

CORE EXPANSION IN UTICA:

UNLOCKING THE OIL WINDOW

• Leveraging proprietary Reservoir

Technology Center (RTC)

• Optimizing lateral placement

• Modifying fluid chemistry, volumes

and frac geometries

>500 barrels oil Recent oil IPs (old completion design)

>1,000 boe/d Recent full-stream IPs (old completion design)


$6.7 mm/well

$11.8 mm/well

$7.4 mm/well

MOST EFFICIENT OPERATOR IN UTICA

Drill Days (Spud to TD)

$M

/ L

ate

ral F

t

Avg. Capex per Lateral Ft.

Days

Rate of Return %

RO

R %

Note: non-operated data based on 49 wells where CHK has a working interest. Includes Gulfport, Hess, AEP and Eclipse. Wells with insufficient production history excluded from ROR comparison.

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


2.2 miles Record for longest useable lateral drilled by CHK (12,106’ in 20 days )

• Focused on continuous improvement in 2014

> Avg. lateral length >6,000 ft. and 22 frac stages

> More than 15% increase in avg. lateral length YOY

> More than 50% increase in avg. frac stages YOY

UTICA

CONTINUOUS IMPROVEMENT

80% ROR on incremental $1.4 mm investment in completion optimization

Spud to Spud Cycle Times (days)

E

$1.4 mm in

reinvested

capital

Avg. Well Cost ($ in mm)


0

20

40

60

80

100

120

1Q'12 2Q'12 3Q'12 4Q'12 1Q'13 2Q'13 3Q'13 4Q'13 1Q'14 2Q'14E 3Q'14E 4Q'14E

Ne

t m

bo

e/d

CASH FLOW GROWTH IN UTICA

>400% YOY production growth (2012 to 2013)

>300% YOY production growth (2013 to 2014E)

30 - 60% YOY production growth (2014E to 2015E)

2Q’14 Avg. Production 67,000 boe/d net

Kensington III (June’14) +200 mmcf/d gross capacity

Cardinal Expansion (4Q’14) +150 mmcf/d gross capacity

Key 2014 Milestones

Natural gas

Oil

NGL


EAGLE FORD

CONTINUOUS IMPROVEMENT

• Spud to completion ratio of 1:1

• Substantial cycle-time improvements

• Testing new completion designs to lower cost

and not impact performance

• Continuing to upgrade rig fleet

95% Multiwell pad drilling in 2014

20% Targeted decrease in spud-to-spud cycle time from 2013 to 2014E

7% Targeted decrease in avg. well costs 2013 to YE’14 target


WHAT TO EXPECT …


REDUCING LEVERAGE

~$6B Reduction in Leverage During the Past 2 years

7%

27%

(1) Assumes takeout of Cleveland-Tonkawa, sale of South and East Texas conventional assets (VPP 5 & 6) and other sales in 2H 2014

($mm) 2012 2014E(1)

Term Loan $2,000 $0

Long-Term Bonds $10,666 $11,821

Credit Facility $418 $381

GAAP Debt $13,084 $12,203

VPPs $3,187 $1,720

Operating & Finance Leases $1,255 -

Subsidiary Preferred $2,500 -

Corporate Preferred $1,531 $1,531

Cash ($287) -

Total Adjusted Net Leverage $21,271 $15,453


DELIVERING ON 2014 PROMISES

Production growth(1) 9 – 12%

Cash flow $5,350 – $5,550 MM

Capital $5,000 – $5,400 MM (Excluding Cap Interest)

Cash costs LOE, G&A and interest expense

Leverage Reduce leverage by 20% YE 2014

(1) Growth range based on 2013 production of 604mboe/day adjusted for asset sales in 2013 and 2014


APPENDIX


• Drilling laterals across section lines optimizes

hydrocarbon recovery and maximizes returns

> Drilling an additional 700’ - 800’ vertical section

> Captures an additional 1.5 BCF per well

> Captures an additional $1.4 mm in PV-10 per well

HAYNESVILLE – CROSS UNIT DEVELOPMENT

X X

X

X

X X

X

X

Work with

competitors to

develop cross

unit laterals

Capture an

additional 6

BCF per

section

Add 2 additional

fracture stages

per well

X X

X

X

X X

X

X

X X

X

X

X X

X

X

X X

X

X

X X

X

X

+10% ROR improvement

85% of 2015 Haynesville wells to be developed cross unit


• ~1.2 bboe of net recoverable resources

• 2Q’14 avg. net production of ~91 mboe/d

> Up 15% YOY, adjusted for asset sales

> More than 101 mboe/d during last week of July

• Averaged 21 operated rigs (2 of which were

spudder rigs) and connected 104 gross wells

in 2Q’14

• ~35% of 2014 estimated E&P capex

• 610 mboe gross EUR per well – 45% ROR(1)

EAGLE FORD

ASSET OVERVIEW

(1) Assumes NYMEX natural gas, oil and NGL prices of $4.00/mcf, $90/bbl and $36/bbl, respectively and ($3.10)/mcf natural gas and ($3.97)/bbl oil for gathering/transportation costs and regional basis differential. Also assumes 115 day spud to TIL cycle time delay. EUR and ROR based on 2014 program

(2) 2Q’14 avg. daily production

CHK Operated Rigs

CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Production mix(2)



MID-CONTINENT

ASSET OVERVIEW

• >500 mmboe of net recoverable resources

in Miss Lime

• >350 mmboe of net recoverable resources

in Granite Wash plays(1)


• Averaged 17 operated rigs and connected

52 gross wells in 2Q’14

• ~20% of 2014 estimated E&P capex

• ~1.9 mm net acres of legacy leasehold

Production mix(2)

(1) Granite Wash plays include Colony Granite Wash, TX Panhandle Granite Wash and Missourian Granite Wash (2) 2Q’14 daily avg. net production

Miss. Lime Granite Washes CHK Operated Rigs




SOUTHERN MARCELLUS

ASSET OVERVIEW

• ~2.7 bboe of net recoverable resources

• 250,000+ net acres

> 68% avg. WI, 57% avg. NRI

• 2Q’14 avg. net production of 58 mboe/d

> Up 67% YOY

• Averaged 1 operated rig and connected 9 gross wells in 2Q’14

• 1 - 2 operated rigs in 2014

• Added second rig in WV panhandle to delineate Utica dry gas potential

(1) 2Q’14 daily average net production

CHK Operated Rigs

Industry Rigs

CHK Leasehold

Production mix(1)


SOUTHERN MARCELLUS

VALUE AND GROWTH OPPORTUNITY

• Potential to unlock significant value

> Combination of dry gas Utica and

liquids-rich S. Marcellus acreage

> Annual organic growth potential >50%

> Ramp activity into expanding capacity

Antero and Rice leasehold positions sourced from public information

$4 - $8 billion(1)

Valuation implied by market multiples Antero Rice CHK Leasehold Opportunity Outline

250,000+ Net Southern Marcellus acres not including 165,000+ net acres of stacked Utica potential

(1) Based on Antero’s market data as of 5/12/2014. Leasehold, production and locations sourced from public information


• ~9 tcfe of net recoverable resources

• 230,000+ net acres(1)

• 39% avg. WI, 34% avg. NRI

• 2Q’14 avg. net production of ~878 mmcfe/d

> Up 12% YOY



• 5 - 7 operated rigs in 2014

• 10 bcfe gross EUR per well – 85% ROR(3)

NORTHERN MARCELLUS

ASSET OVERVIEW

(1) Excludes acreage off main development fairway (2) 2Q’14 daily average net production (3) Assumes NYMEX natural gas prices of $4.00/mcf and ($1.35)/mcf for gathering/transportation costs and regional basis differentials. Also assumes 120 day avg. spud to TIL cycle time delay. EUR and ROR based on 2014 program

CHK Operated Rigs Industry Rigs CHK Leasehold

Production mix(2)

- 47% Drilling cost savings in last 12 months


NORTHERN MARCELLUS

DRIVING VALUE

Value Creation, $M

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 30 60 90 120 150 180 210 240 270

Gas (

mcf/

d)

Days On

Standard Completion Design

Gross Daily Production Rates

$1 million 2014 savings reinvested into completions optimization

55% ROR on reinvested capital

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 30 60 90 120 150 180 210 240 270

Gas (

mcf/

d)

Days On

Standard Completion Design Enhanced Completion Design

Gross Daily Production Rates


NORTHERN MARCELLUS

IMPACT OF HOLDING PRODUCTION FLAT

$4 - $7 billion Cumulative net FCF over the next 10 years

$300 mm - 5 rigs Net capital required per year to hold gross production flat at 2.2 bcf/d

Assumes $4.00 and $5.00 NYMEX pricing and is fully burdened with differentials and cycle time


• 4+ bboe of net recoverable resources


> Up 373% YOY and 34% sequentially



• Over 1 million net acres

• 1,325 mboe gross EUR per well – 45% ROR(1)

UTICA

ASSET OVERVIEW

(1) EUR assumes ethane recovery to meet ATEX commitment. ROR assumes NYMEX natural gas, oil and NGL prices of $4.00/mcf, $90/bbl and $36/bbl, respectively and ($7.00)/bbl oil and ($1.30)/mcf natural gas for gathering/transportation costs and regional basis differentials. Also assumes 185 day avg. spud to TIL cycle time delay. EUR and ROR based on 2014 program

(2) Utica dry gas acreage includes 165,000+ acres that overlap Southern Marcellus (3) 2Q’14 daily average net production

CHK/TOT JV Outline CHK Operated Rigs Industry Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Production mix(3) >250,000 net acres in wet gas window

>300,000 net acres in oil >540,000 net acres in dry gas(2)

71% avg. WI, 57% avg. NRI


CORE EXPANSION IN UTICA:

DRY GAS OPPORTUNITY

• 2,000+ potential locations

• Expect 10+ bcfe EURs

• 2014 delineation

> Test in Wetzel County, WV

> Completion scheduled for late August

> Added second rig in WV panhandle

5.9 Mmcf/d Q1 ‘12

5.1 Mmcf/d Q2 ‘12

6.9 Mmcf/d Q4 ‘11

14.7 Mmcf/d Q3 ‘11

12.7 Mmcf/d Q3 ‘12

17.7 Mmcf/d Q3 ‘12

8.6 Mmcf/d Q2 ‘12

18.1 Mmcf/d Q2 ‘13

20.5 Mmcf/d Q3 ‘13

5.9 Mmcf/d Q2 ‘12

30.0 Mmcf/d Q1 ‘13

32.5 Mmcf/d Q2 ‘13

22.5 Mmcf/d Q3 ‘12

Note: Chesapeake peak rates based on old frac design during initial acreage capture

$4 - $7 billion Implied value based on recent transactions

>330,000 acres Net, dry gas acres in Jefferson County, OH and W.V.

6.1 Mmcf/d

7.1 Mmcf/d

6.7 Mmcf/d

5.9 Mmcf/d

5.1 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

CHK Leasehold Oil Window Wet Gas Window Dry Gas Window CHK rates Industry peer rates


NET ASSET VALUE AND UPSIDE POTENTIAL

(1) Based on commodity prices of $4.50/mcf and $90.00/bbl for natural gas and oil, respectively, >20,000 risked drilling locations, net debt, NCI and

other liabilities of $13 billion for a total net asset value of $32 billion.

CHK

$40 NAV/share(1)


$1,500

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

$396

$2,299

$1,015

$1,800

$1,100

$1,500

$1,700

2.75%(1) 3.25% 2.5%(1) 2.25%(1) 3mL+3.25%(3) 6.875% 5.375% 4.875% 5.75%

6.5% 7.25% 6.625% 6.125%

6.25%(2)

$500

(1) Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes (2) Euro-denominated notes with a principal amount based on the exchange rate of $1.3692 to €1.00 at 6/30/2014 (3) All-in yield composed of 3.25% spread and 3mL

Convertibles Other Senior Notes

Sr. Debt: $11.8 billion

6/30/2014 WACD – 5.0%

Avg. Maturity: 5.4 years

$0

SENIOR NOTE PROFILE


CHK’S HEDGING STRATEGY INCREASES

CASH FLOW CERTAINTY IN 2014

69% 65%

Natural Gas Oil

41%

Swaps

24% Three-Way

Collars

$4.10 - $4.37/mcf

NYMEX

$4.09/mcf

NYMEX

$4.50-$5.24/mcf

NYMEX

$94.25/bbl

NYMEX

• Ensures delivery of business strategy by securing prices

• Proactively managing basis

Downside protection for 2H’14 as of 7/31/2014


• ~38% of estimated April - October 2014 natural gas production will receive an avg. basis diff. of ($0.68)/mcf

• ~10% of estimated April - October 2014 natural gas production will receive Gulf Coast linked pricing

• ~35% of April-October 2014E natural gas production sold in-basin under firm purchase agreements

NE MARCELLUS SALES POINTS AND

BASIS HEDGES

1Q’14A

Diff. to HH

Apr. – Oct. ‘14 Basis Hedges

Apr. – Oct. ‘14 Hedged Volumes

(mmcf/d)

Tetco M3/Transco z6 NYC $3.25 ($0.62) 240

Dominion South ($0.49) ($0.90) 30

WTD. Avg. Basis Hedged

April – Oct ‘14 ($0.68)

34%

9% 9% 3%

36%

9% Tetco M3/TCO z6 (NYC)

Dominion South Point

TGP Zn1 500 Line

TGP Zn4 200L

In-Basin Firm

In-Basin Floating

Estimated Apr. - Oct ‘14 NE Sales Points


UTICA AND SOUTHERN MARCELLUS SALES POINTS

1Q’14A

Diff. to HH

Apr. – Oct. ‘14 Basis Hedges

Apr. – Oct. ‘14 Hedged Volumes

(mmcf/d)

TCO ($0.03) ($0.22) 105

Dominion South ($0.49) ($0.90) 45

WTD. Avg. Basis Hedged

Apr. – Oct. ‘14 ($0.42/mcf)

39%

18%

21%

6%

10% 6%

TGP Zn1 500L (Gulf Coast)


TGP Zn4 200L

TETCO M3

TCO

TETCo M2

30%

39%

10%

13%

8% TGP Zn1 500L (Gulf Coast)

Tetco WLA (Gulf Coast)


TGP Zn4 200L

TCO

Estimated Apr. – Oct. ‘14 Sales Points Estimated 2015 Sales Points

• ~31% of estimated Apr. - Oct. 2014 natural gas production will receive an avg. differential of ($0.42)/mcf

• ~40% and ~70% of 2014E and 2015E natural gas will receive Gulf Coast linked pricing, respectively


ADJUSTED PRODUCTION GROWTH

Oil (mmbbls) 41.1 (5.6) 35.5 11 – 15%

NGL (mmbbls) 20.9 (1.9) 19 63 – 68%

Natural Gas (bcf) 1,095 (99.5) 995.5 4 – 6%

Total (mmboe) 244.4 (24) 220.4 9 – 12%

2014E Adjusted

Production Growth

2013 Reported

Production

E&P

Sales

2013 Adjusted

Production

Asset Sale Adjustments (mmboe) 239 - 246

2014E

Adjusted

Production

2013

Adjusted

Production

220

244

2013

Reported

Production

(10.9)

(13.1)

2013 E&P

Sales

2014 E&P

Sales


(1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The

company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: (i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information

regarding these types of items. (2) In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP

($ in mm, except per share data)

Three Months Ended: 6/30/2014 6/30/2013

Net income available to common stockholders $145 $457

Adjustments, net of tax: Unrealized (gains) losses on derivatives (19) (325)

Restructuring and other termination costs 20 5

Impairments of fixed assets and other 25 143

Net gains on sales of fixed assets (57) (68)

Impairments of investments 3 –

Net (gains) losses on sales of investments – 6

Losses on purchases of debt and extinguishment of other financing 120 44

Other (2) 3

Adjusted net income available to common stockholders(1) $235 $265 Preferred stock dividends 43 43

Premium on purchase of preferred shares of a subsidiary – 69

Earnings allocated to participating securities 3 11

Total adjusted net income attributable to CHK $281 $388

Weighted average fully diluted shares outstanding(2) 776 763

Adjusted earnings per share assuming dilution(1) $0.36 $0.51

RECONCILIATION


(1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

(2) Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.

(3) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because: (i) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted ebitda is more comparable to estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

($ in mm)

Three Months Ended: 6/30/2014 6/30/2013

Cash provided by operating activities $1,352 $1,281 Changes in assets and liabilities (83) 85

Operating cash flow(1)

$1,269 $1,366

Net income $230 $625 Interest expense 27 104

Income tax expense 141 384

Depreciation and amortization of other assets 79 76

Natural gas, oil and NGL depreciation, depletion and amortization 661 645

EBITDA(2)

$1,138 $1,834

Adjustments: Unrealized losses on natural gas, oil and NGL derivatives – (576)

Restructuring and other termination costs 33 7

Impairments of fixed assets and other 40 231 Net gains on sales of fixed assets (93) (109)

Impairments of investments 5 –

Net (gains) losses on sales of investments – 10

Losses on purchases of debt and extinguishment of other financing 195 70

Net income attributable to noncontrolling interests (39) (45)

Other (2) 2

Adjusted EBITDA(3) $1,277 $1,424

RECONCILIATION


CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER

3.25% Senior Notes due 2016 #165167CJ4 CHK16

6.25% Senior Notes due 2017 #027393390 N/A

6.50% Senior Notes due 2017 #165167BS5 CHK17

7.25% Senior Notes due 2018 #165167CC9 CHK18A

3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19

6.625% Senior Notes due 2020 #165167CF2 CHK20A

6.875% Senior Notes due 2020 #165167BU0 CHK20

6.125% Senior Notes Due 2021 #165167CG0 CHK21

5.375% Senior Notes Due 2021 #165167CK21 CHK21A

4.875% Senior Notes Due 2022 #165167CN5 CHK22

5.75% Senior Notes Due 2023 #165167CL9 CHK23

2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35

2.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/

#165167CA3

CHK37/

CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38

4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD

5.0% Cumulative Convertible Preferred Stock (Series 2005B) #165167834/

#165167826 N/A

5.75% Cumulative Convertible Preferred Stock

#U16450204/

#165167776/

#165167768

N/A

5.75% Cumulative Convertible Preferred Stock (Series A)

#U16450113/

#165167784/

#165167750

N/A

Chesapeake Common Stock #165167107 CHK

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CHESAPEAKE HEADQUARTERS

BRAD SYLVESTER, CFA Vice President — Investor Relations and Communications

DOMENIC J. DELL'OSSO, JR. Executive Vice President and Chief Financial Officer

Investor Relations department can be reached by phone at (405) 935-8870 or by email at [email protected]

CORPORATE CONTACTS

mailto:[email protected]