Bank of america 20151110

BANK OF AMERICA

2015 GLOBAL ENERGY CONFERENCE

November 10, 2015

FORWARD-LOOKING STATEMENTS

2BANK OF AMERICA – 2015 GLOBAL ENERGY CONFERENCE

• 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. They include statements that give our current

expectations or forecasts of future events, production and well connection forecasts, estimates of operating costs, planned development drilling and expected

drilling cost reductions, capital expenditures, expected efficiency gains, our ability to improve margins, reduce operating and G&A expenses, optimize base

production, and use leading-edge technology to drive capital efficiency, the timing of anticipated noncore asset sales and proceeds to be received therefrom,

projected cash flow and liquidity, business strategy and other opportunities, plans and objectives for future operations (including restructuring of midstream

gathering agreements), and the assumptions on which such statements are based. 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.

• In addition, 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 also 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. 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.

3Q’15 FINANCIAL AND OPERATIONAL RESULTS

(1) Includes stock-based compensation

(2) Adjusted for asset sales

(3) Oil and NGLs collectively referred to as “liquids”

Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 18 – 19


ADJ. EBITDA

$560mm

LIQUIDS MIX(3)

28% of total production3% YOY(2)

ADJ. EARNINGS/FDS

($0.05)

ADJ. PRODUCTION

667 mboe/d

PROD. and G&A EXP.

ADJ. OIL PRODUCTION

4% YOY(2)

114 mbo/d

9% YOY

$4.88/boe(1)

BUSINESS DELIVERY


Operational Leadership

Portfolio Strength & Flexibility

Financial Stability

Chesapeake continues to execute on its strategy

NEAR-TERM STRATEGY

BANK OF AMERICA – 2015 GLOBAL ENERGY CONFERENCE 5

Preserve

cash flow

generation

capability

• Enhance field

development

• Leading-edge

technology to

drive capital

efficiency

Use operating

and capital

flexibility as

a strength

• Optimize base

production

• Focus on core

positions

Improve

margins

• Restructure

midstream

contracts

• Reduce field

operating

expenses

• Reduce G&A

expenses

Maximize

liquidity

• Amended credit

facility

• Divest noncore

assets

FINANCIAL STABILITYMAXIMIZING LIQUIDITY

• Proactively working to increase liquidity

˃ Amended credit facility agreement maturing in 2019

˃ Noncore divestitures expected to total $200 – $300mm by 1Q’16

• Maintaining capital discipline during challenging commodity environment

• On target to beat February production guidance for FY 2015 despite:

˃ $500mm capital spending reduction

˃ Average voluntary curtailment of ~35,000 boe/d YTD


Portfolio strength and flexibility provides financial stability;

spending less and producing more

• Financial security and flexibility

> Borrowing base confirmed at

$4.0 billion

> Facility maturing in 2019

> Covenants restructured in light of low

commodity prices

> $2.4 billion of additional secured debt

available, should conditions warrant

FINANCIAL STABILITYCREDIT FACILITY AMENDMENT


$5.7 billionIn cash and undrawn credit facility

on 9/30/15

• Operational flexibility

> Reduced commitments and

continually improving capital

efficiency positions Chesapeake to

run a reduced capital program in

2016 to support liquidity focus

> Depth of portfolio allows for

continued, methodical sales of

noncore assets to enhance value

OPERATIONAL LEADERSHIP


• Enhanced base production of

existing assets

˃ Generated an additional 7 mmboe

net YTD

˃ Focused programs on

compression and artificial lift

˃ Reduced downtime through

enhanced winterization activities

~7 mmboeAdditional net base production

YTD vs. 2015 budget forecast

(1) Lateral lengths reported are drilled footage, not completed footage

9,395 9,36610,020

12,976 13,192

4,464

6,186

4,998

7,371

5,955

Miss Lime PRB Haynesville Utica Eagle Ford

2015 Record LL (ft.)

Avg. 2014 LL (ft.)

• Development teams extending

technological limits with operations

program

˃ Drilled the longest laterals(1) in each

of our major operating areas in 2015;

significantly enhancing economics

˃ Long laterals improve capital efficiency

($/boe) by 20 – 25% companywide

SUBSTANTIAL GROWTH OPPORTUNITIESMID-CONTINENT: MERAMEC AND OSWEGO

• Meramec

˃ First well 27 days spud to RR

˃ Second well 18 days spud to RR

• Oswego

˃ Three Oswego wells drilled to date


(1) Assumes NYMEX natural gas price of $3.00/mcf held constant

(2) Assumes $7.1mm well cost

(3) Assumes $3.2mm well cost

Production Mix Production Mix

Meramec$36 PV-10 Break-Even(1)(2)

Oswego$37 PV-10 Break-Even(1)(3)

NGL

Oil

Gas

~1,200 locationsMeramec and Oswego Limestone

CHK

Industry

CHK Hughes Trust 1H

Oswego Test

2052 BOEPD Peak

(93% Oil)

CHK Rouce 4-17-10 1H

Initial CHK 9,350’

Meramec well

CHK Wittrock 16-16-9 1H

9,220’ Meramec well

CHK Stangl 36-16-9 1H

10,000’ Meramec well

1723 BOEPD IP

(85% Oil)

1374 BOEPD IP

(80% Oil)

1309 BOEPD IP

(79% Oil)

Mississippian/Meramec

Oswego

All Rights

Shallow Rights

(1) Assumes NYMEX natural gas price of $3.00/mcf.

SUBSTANTIAL VALUE UNDER HBP ACREAGEUPPER MARCELLUS

• Recent successful appraisal of the

Upper Marcellus unlocks more

than 1,000 economic locations(1)

˃ Well 1 peak rate 19 mmcf/d

˃ Well 2 peak rate 17 mmcf/d

˃ Future test wells in Susquehanna

and Wyoming counties

• Favorable development flexibility

as position is held by production

• No communication between Upper

and Lower Marcellus confirmed


>1,000 locationsBreak-Even (PV-10)(1) Upper Marcellus

Test Well 119 mmcf/d

Test Well 217 mmcf/d

OPTIMIZING VALUE FROM BASE PRODUCTIONUTICA SHALE

• Operating more efficiently

˃ Compressor/Artificial lift

optimization

˃ Pressure maintenance

program

˃ Choke management

˃ Better winter ops preparation

• Midstream improvements

˃ Line pressure decrease

˃ Fewer disruptions


12% increase2015 1H production driven by

base optimization

0

20

40

60

80

100

120

140

160

180

Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15

Avg

Da

ily R

ate

(m

bo

e/d

)

2015 Gross Operated Base Production

Incremental Production

Avg Mboe/d

Previous Trend

Current Trend

mboe/d

DEVELOPMENT OPTIMIZATIONEAGLE FORD

• Leveraging Chesapeake’s

technical advantage

˃ First wells with laterals greater

than 12,500’ on flowback

˃ 13,000’ wells provide capital

reduction of more than 20% when

compared to two 6,500’ laterals

˃ Extended laterals improve

Eagle Ford capital efficiency

($/boe) by ~20%


Days Days

(1) Lateral lengths reported are drilled footage, not completed footage

Rogers E-1H;

12,611’ LL(1)

Faith-San Pedro F-4H;

13,192’ LL(1)

Current Rigs

CHK Leasehold

County

MATURITY WINDOW

Oil Window

Dry Gas Window

Wet Gas Window

Transition Window

0

600

1200

1800

0 5 10 15 20 25 30 35 40 45

Bopd

Oil Production RateRogers ExtendedLateral

Control 6400'

0

600

1200

1800

0 5 10 15 20 25 30 35 40

Bopd

Oil Production RateFaith ExtendedLateral

Control 6500'

TURNING EFFICIENCY INTO VALUEHAYNESVILLE

• Extended laterals

˃ Two 7,500’ lateral tests flowing an average of

16.1 mmcf/d for more than 170 days

˃ Production test of first three 10,000’ laterals in

4Q’15

˃ Technological innovation and continued cost

improvement are driving value into the

Haynesville


0

5

10

15

20

25

0 50 100 150

Avg

Daily

Gas R

ate

(m

mcf/

d)

Days

Haynesville Shale –Extended Lateral Performance

Nguyen 7500 Rate (mcfpd)

Nguyen 7500 Avg FTP (psi)

Unit Rate (mcfpd)

Unit FTP (psi)

10 mmcf/d higher

$289 $275 $246 $241 $234

$209

13

18 18 19

15

18

0

5

10

15

20

25

30

$0

$50

$100

$150

$200

$250

$300

Q2 Q3 Q4 Q1 Q2 Q3

2014 2014 2014 2015 2015 2015

Wells

Sp

ud

$/F

oo

t

Avg(CPF) Well Count

Drilling Cost Per Foot

Producing 7,500’ Nguyen wells

10,000’ lateral in progress

7,500 – 8,500’ laterals in progress

CHK Operated Rigs

CHK Leasehold

Multilateral Wells

Multisection

Extended Laterals

APPLYING NEW TECHNOLOGIESMID-CONTINENT

• Multilateral wells

˃ First multilateral expected to TIL

mid-December

˃ Potential to spread technology to other

plays – significant cost saving potential

• Multisection extended laterals

˃ Drilled two extended multisection laterals

˃ Saves ~$1.4mm as compared to two

standard laterals


27% decreasein D&C costs compared to drilling

two standard laterals

Multilateral

Wilber 26-27-11 1H

TD 10/8/2015

Extended Laterals

JJJ 23-25-11 1H

Est TIL 11/20/2015

Sunny 23-25-11 1H

TIL in Q4 2015

Extend and Multilateral Wells

Mississippi Lime

County

CHK Section Summary

PORTFOLIO STRENGTH AND FLEXIBILITY

(2) Assumes NYMEX natural gas price of $3.00/mcf held constant(1) Assumes NYMEX oil price of $50/bbl held constant


$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

PRB SUSSEX MISS LIME EAGLE FORD MID-CONSTACK

Oil Break-Even (PV-10)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

HAYNESVILLE UTICA DRY UTICA WET MARCELLUS

Natural Gas Break-Even (PV-10) (2)(1)

Chesapeake’s diverse portfolio of highly efficient investments

is built to withstand the current commodity price environment

CHESAPEAKE’S STRATEGIC SCORECARD


Chesapeake is executing on its strategy to simplify and

optimize the business for a prosperous future

Financial

Stability

Maximize liquidityCredit facility maturing in 2019; Covenants restructured in light of

low commodity prices

Restructure

midstream contractsFinalized new gas gathering agreements in the Haynesville and

dry gas Utica

Divest noncore

assetsNoncore divestitures expected to total $200 – $300mm by 1Q’16;

evaluating substantial noncore assets still in the portfolio

Improve marginsSignificant improvements in LOE and G&A; ~$200mm removed

from cost structure

Operational

Leadership

Base production

optimizationOptimized base production generated an additional 7 mmboe

net vs. 2015 base production forecast

Field development

optimization Chesapeake drilled record laterals in major operating areas

in 2015; significantly enhancing economics

Portfolio Strength

and Flexibility

High-grade and

optimize portfolio

Optimization and reservoir characterization has created a

diverse portfolio with multiple economic investment opportunities

at current prices

Appraise HBP

acreage positionSubstantial progress toward appraising HBP position;

currently appraising Meramec, Oswego and Upper Marcellus

APPENDIX


(1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or diluted earnings per share. 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 GAAP because:

i. Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas 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) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

RECONCILIATION OF ADJUSTED

EARNINGS PER SHARE


($ in mm)

Three Months Ended: 9/30/2015 9/30/2014

Net income available to common stockholders ($4,695) $169

Adjustments, net of tax:

Unrealized (gains) losses on commodity derivatives 58 (384)

Unrealized gains on supply contract derivatives (58) --

Restructuring and other termination costs 44 (9)

Provision for legal contingencies -- 62

Impairment of oil and natural gas properties 4,506 --

Impairments of fixed assets and other 66 9

Net (gains) losses on sales of fixed assets (1) (54)

Repurchase of preferred shares of CHK Utica -- 447

Other (3) 11

Adjusted net income available to common stockholders(1) ($83) $251

Preferred stock dividends 43 43

Earnings allocated to participating securities -- 3

Total adjusted net income attributable to CHK ($40) $297

Weighted average fully diluted shares outstanding(2) 777 776

Adjusted earnings per share assuming dilution(1) ($0.05) $0.38

RECONCILIATION OF ADJUSTED EBITDA

(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 an oil and natural gas company's ability to generate cash that 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 oil and natural gas 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 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:

(1) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

(2) Adjusted ebitda is more comparable to estimates provided by securities analysts.

(3) 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.

Accordingly, adjusted ebitda 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.


($ in mm)

Three Months Ended: 9/30/2015 9/30/2014

Cash provided by operating activities $318 $1,184

Changes in assets and liabilities 158 109

Operating cash flow(1) $476 $1,293

Net income ($4,639) $692

Interest expense 88 17

Income tax expense (benefit) (937) 437

Depreciation and amortization of other assets 31 37

Oil, natural gas and NGL depreciation, depletion and amortization 488 688

EBITDA(2) ($4,969) $1,871

Adjustments:

Unrealized losses on oil, natural gas and NGL derivatives 67 (622)

Unrealized gains on supply contract derivatives (70) --

Restructuring and other termination costs 53 (14)

Provision for legal contingencies -- 100

Impairment of oil and natural gas properties 5,416 --

Impairments of fixed assets and other 79 15

Net (gains) losses on sales of fixed assets (1) (86)

Net income attributable to noncontrolling interests (13) (30)

Other (2) 2

Adjusted EBITDA(3) $560 $1,236

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/

#165167826N/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

HEADQUARTERS

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CORPORATE CONTACTS

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 at [email protected]

http://www.chk.com/

mailto:[email protected]

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Bank of america 20151110