Bank of America Merrill Lynch 2014 Energy Conference

Bank of America Merrill Lynch

2014 Energy Conference November 13, 2014

2 I BOAML ENERGY CONFERENCE 11/13/2014

• 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, planned 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. Further, pending divestiture transactions are subject to closing conditions and may not be completed in the

time frame anticipated or at all. In particular, we caution you that our October 2014 purchase and sale agreement with Southwestern Energy Company, in

which we agreed to sell certain assets in the Marcellus Shale and Utica Shale for approximately $5.375 billion, is subject to closing conditions, including

third-party consents and waiver of participation rights. These closing conditions may not be completed in the time frame anticipated or at all. 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; uncertainties regarding legal claims and governmental proceedings, including royalty

claims, and the adequacy of our provision for legal contingencies; 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.

• 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


WHERE WE ARE TODAY

CORPORATE PROGRESSION

2013 2014 2015 +

TRANSFORMATION

FOUNDATION

E&P LEADERSHIP


• 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


3Q’14 OPERATIONAL AND FINANCIAL RESULTS

11% YOY(1)

726 mboe/d

TOTAL ADJ. PROD. LIQUIDS MIX ADJ. OIL PROD.

(1) Adjusted for asset sales

(2) Oil and NGL collectively referred to as “liquids”

(3) Adjusted earnings per fully diluted share and adjusted EBITDA are non-GAAP financial measures. A reconciliation of non-GAAP financial measures to comparable

GAAP financial measures appears on pages 27 – 28

29% 28% in 2Q’14

5% Q/Q(1)

118.9 mbbls/d

of Total Production(2) to

ADJ. EARNINGS/FDS

12% YOY

$0.38(3)

ADJ. EBITDA

7% YOY

$1.24 billion(3)

CAPEX

8% YOY

$1.35 billion


CAPITAL DISCIPLINE

$14.2

~$5.7

(1) Operating Cash Flow before changes in assets and liabilities (2) 2014 based on midpoint of company Outlook issued on 11/5/2014; capex includes capitalized interest, but excludes the exchange of properties with RKI Exploration and

Production, LLC for ~$450 million in August 2014

$7.6

(2)

$ in

billio

ns

(1)

60% Decrease in Capital Investment

36% Increase in Operating Cash Flow


GROWING PRODUCTION WHILE MANAGING

INVENTORY

Inve

nto

ry C

ou

nt

mm

bo

e


42 - 49 Liquids Focused Rigs

13 - 16 Natural Gas Focused Rigs

55 - 65 Total Operated Rigs

OPERATIONS UPDATE

2014E Avg. Operated Rig Count

(1) Operating Cash Flow before changes in assets and liabilities (2) Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the august 2014 exchange of properties with RKI Exploration and Production, LLC. (3) Adjusted for asset sales in 2013 and 2014 (4) Net of Utica and PRB drilling carries; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest (5) Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays

• Operating cash flow(1) for first nine months of 2014 of approximately $4.2 billion, compared to capital expenditures of $3.5 billion(2)

• Adjusted production(3) for first nine months was 12% higher than year-ago levels

• Achieved year-end estimated exit rate of 730 mboe/d in September, 2014

3Q’14 Daily Avg. Net Production (mboe/d)

(5)

17-20

5-6

(5)

2014E % of E&P Capex by Play(2)(4)

<5% <5%

~

~

~ ~

~

~

~

~


CAPTURING MORE FOR LESS

NORTHERN DIVISION

Marcellus North: 30% Improvement Utica: 54% Improvement

Powder River Basin: 50% Improvement

(1) (1)

(1)

Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well

(1) 2014 estimated D&C costs per well and net reserves booked per well are as of 9/30/2014.


CAPTURING MORE FOR LESS

SOUTHERN DIVISION

Haynesville: 64% Improvement Eagle Ford: 34% Improvement

Mississippian Lime: 39% Improvement

(1) (1)

(1)

Note: Capex / EUR is defined as net drilling and Completion (D&C) costs per well divided by net estimated ultimate reserves booked per well

(1) 2014 estimated D&C costs per well and net reserves booked per well are as of 9/30/2014.


• 3Q‟14 avg. net production of ~102 mboe/d

> Up 12% sequentially

• Averaged 21 operated rigs (plus 3 spudder rigs)

• ~40% of 2014 estimated E&P capex

• Avg. completed well cost of ~$6.0 million(1)

EAGLE FORD

ASSET OVERVIEW

(1) As measured from Jan-July

CHK Operated Rigs

CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Production mix

449,000 net acres 61% avg WI

Eagle Ford Avg. Daily Net Production (mboe/d)


• Drilling performance continues to improve with

increased pad drilling

• Centralized production facilities provide

efficiencies

• 2014 avg. completed lateral lengths of 6,300

feet and 20 frac stages

• 135 day spud to sales cycle time in 3Q‟14

> Wells spent waiting on completion or waiting on

pipeline connection markedly shrinking

• Avg. peak production of 89 wells connected to

pipeline in 3Q‟14 was 840 boe/d

• Added 2 frac crews in 4Q‟14 – up to 9 currently

EAGLE FORD DRILLING PERFORMANCE

(1)

(1) 3Q‟14 avg. rig count




• Averaged 7 operated rigs and connected 77

gross wells in 3Q‟14


> Decreased 16% since 2012 amid increasing

lateral lengths and frac stages

UTICA

ASSET OVERVIEW


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

Production mix

>1 million net acres 61% avg WI


POWDER RIVER BASIN OIL GROWTH ENGINE

• Closed transaction with RKI in August „14 –

exchanged nonoperated northern acreage for

RKI‟s southern acreage and $450 mm cash

• 3Q‟14 avg net production of ~14 mboe/d

– Up 26% sequentially

• Averaged three operated rigs in 3Q‟14 and

connected 17 gross wells

• Buckinghorse Plant (4Q'14) expected to add

120 mmcf/d processing capacity


• Multiple stacked formation tests in early 2015:

> 1 in Teapot

> 1 in Shannon

> 2 in Parkman

> 7 in Sussex


CHK Operated Rigs

CHK Leasehold

Production mix



HAYNESVILLE

ASSET OVERVIEW


• 3Q‟14 avg. net production of ~562 mmcfe/d





CHK Operated Rigs

CHK Leasehold

Production mix


Hayneville EUR performance (mboe)


HAYNESVILLE D&C IMPROVEMENT IMPACTS

$8,100

$7,200

$7,000

$7,500

$8,500

$4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000

August 2013 Actual

Reducing chemicals(FR/Gel)

Toe Prep Efficency

Jan 2014 Well CostTarget

Remove Resin CoatedProppant

Ops Procedures (24 Hrs)

Design Efficiencies /Rentals

Increasing cluster/stg

Manufacturing Mode

Drilling Efficiencies

2014 Mid-Year Results

Non-InterventionCompletion

2015 Target

Cross Unit Lateral

Cross Unit 2015 Target

(1) $4/mcf, fully burdened differential of $1.29 ; (2) Well Count includes Operated Haynesville Shale Wells

6750

6950

7150

7350

7550

7750

7950

8150

8350

8550

20% 40% 60%

ROR (%) Haynesville Shale Well Cost Progress Report ($m)

>17% Capex Improvement in 17 wells from the previous 628

$7.5 mm Achieved 2015 Cross Unit Target after 17 of 23 wells D&C‟d in 2014

34% Improvement in ROR for Drilling a Cross unit Lateral

$4.00/MCF


REDUCING LEVERAGE

~$6.5B Reduction in Leverage During the Past 2 Years

~10%

(1) Assumes takeout of Cleveland-Tonkawa, sale of South and East Texas conventional assets (VPP 6) in 2H 2014 (2) Excludes approximately $5.4 billion in potential proceeds from the proposed Southern Marcellus asset sale, subject to close in December 2014

($mm) 2012 2014E(1)(2)

Term Loan $2,000 --

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

Credit Facility $418 --

GAAP Debt $13,084 $11,821

VPPs $3,187 $1,720

Operating & Finance Leases $1,255 --

Subsidiary Preferred $2,500 --

Corporate Preferred $1,531 $1,531

Total Adjusted Leverage $21,558 $15,061 ~30%


EXECUTING OUR PLAN

Production growth(1) 9 – 12%

Cash flow $5,250 – $5,450 MM

Capital $5,000 – $5,400 MM(2)

Cash costs LOE, G&A and interest expense

Leverage Reduce adjusted leverage by 30%

YE 2014

(1) Growth range based on 2013 production of 604mboe/day adjusted for asset sales in 2013 and 2014 (2) Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the August 2014 exchange of properties with

RKI Exploration and Production, LLC.


APPENDIX


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


UPSIDE POTENTIAL

CHK


• 3Q‟14 avg. net production of ~882 mmcfe/d





NORTHERN MARCELLUS

ASSET OVERVIEW

(1) Excludes acreage off main development fairway (2) As measured from Jan-July

CHK Operated Rigs CHK Leasehold

Production mix(2)

230,000+ net acres(1)

39% avg WI


MID-CONTINENT

ASSET OVERVIEW


• Averaged 18 operated rigs and connected

63 gross wells in 3Q‟14

• 249,000 net acres actively being developed

in aggregate

˃ Mississippian Lime

˃ 164,000 net acres

˃ 44% avg WI, 36% avg NRI

˃ Granite Wash plays(1)

˃ 85,000 net acres

˃ 83% avg WI, 67% avg NRI

˃ ~1.9 mm net acres of legacy leasehold

• ~20% of 2014 estimated E&P capex

• Avg. completed well cost of $3.1 million in

the Mississippian Lime(3)

(1) Granite Wash plays include Colony Granite Wash, TX Panhandle Granite Wash and Missourian Granite Wash (2) 3Q‟14 daily avg. net production (3) As measured from Jan-July

Miss. Lime Granite Washes CHK Leasehold CHK Operated Rigs

Production mix(2)


CURRENT HEDGE POSITION

72% 64%

Natural Gas Oil

42%

Swaps

26% Three-Way

Collars

$4.11 - $4.37/mcf

NYMEX

$4.09/mcf

NYMEX

$4.50-$5.24/mcf

NYMEX

$94.22/bbl

NYMEX

Note: Hedged positions as of 11/1/2014 based on production estimates provided in 11/5/2014 Outlook; 26% of 2014 gas production is hedged under collar

arrangements with upside to average NYMEX price of $4.37/mcf and exposure below average NYMEX price of $3.49/mcf

Q4 2014 Total 2015

Natural Gas Hedges Volume (bcf) 194 319

$4.31 Price ($/mcf) $4.12

Crude Oil Hedges Volume (mmbls) 7,197 16,837

Price ($/bbl) $94.22 $93.39


• Average transportation rates of $0.22

per mcf per day for balance of 2014

and $0.24 per mcf per day for 2015

• Gulf Coast Market Access

> 440 MMcfd to the Gulf Coast for 2015

> 732 MMcfd to the Gulf Coast

beginning in 2016

• Upper Midwest/Canadian Market

Access

> 200 MMcfd of capacity to Dawn

market in 2017

• Local Market Access

> 96 MMcfd to local markets

UTICA DOWNSTREAM MARKETING ADVANTAGE

Utica

Gulf

Coast

Dawn


$1,500

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

$396

$2,263

$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 $1.2631 to €1.00 at 9/30/2014 (3) All-in yield composed of 3.25% spread and 3mL

Convertibles Other Senior Notes

Sr. Notes: $11.8 billion

9/30/2014 WACD – 5.0%

Avg. Maturity: 5.2 years

$0

SENIOR NOTE PROFILE


($ in mm, except per share data)

Three Months Ended: 9/30/2014 9/30/2013

Net income available to common stockholders $169 $156

Adjustments, net of tax: Unrealized losses on derivatives (384) 118

Restructuring and other termination costs (9) 39

Impairments of fixed assets and other 9 55

Net gains on sales of fixed assets (54) (82)

Net gains on sales of investments - (2)

Provision for legal contingencies 62 -

Other 11 (2)

Redemption of preferred shares of a subsidiary(1) 447 -

Adjusted net income available to common stockholders(2) $251 $282 Preferred stock dividends 43 43

Earnings allocated to participating securities 3 3

Total adjusted net income attributable to CHK $297 $328

Weighted average fully diluted shares outstanding(3) 776 765

Adjusted earnings per share assuming dilution(2) $0.38 $0.43

(1) All adjustments to net income available to common stockholders reflected net of tax other than the redemption of preferred shares of a subsidiary. (2) 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. Management believes that ―adjusted net income attributable to common stockholders‖ represents a useful corollary to net income attributable to common stockholders because it provides useful information regarding our ongoing operations and is widely used by investors, analysts and rating agencies in the valuation, rating and investment recommendations of companies.

(3) In millions. 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: 9/30/2014 9/30/2013

Cash provided by operating activities $1,184 $1,381 Changes in assets and liabilities 109 31

Operating cash flow(1)

$1,293 $1,412

Net income $692 $240 Interest expense 17 40

Income tax expense 437 147

Depreciation and amortization of other assets 37 79

Natural gas, oil and NGL depreciation, depletion and amortization 688 652

EBITDA(2)

$1,871 $1,158

Adjustments: Unrealized losses on natural gas, oil and NGL derivatives (622) 191

Restructuring and other termination costs (14) 63

Impairments of fixed assets and other 15 89

Net gains on sales of fixed assets (86) (132)

Net gains on sales of investments -- (3)

Net income attributable to noncontrolling interests (30) (38)

Provision for legal contingencies 100 --

Other 2 (3)

Adjusted EBITDA(3) $1,236 $1,325

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 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 net income 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.


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]