Bank of America Merrill Lynch 2014 Energy Conference November 13, 2014

FORWARD-LOOKING STATEMENTS •

•

•

•

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.

2 I BOAML ENERGY CONFERENCE 11/13/2014

WHERE WE ARE TODAY

CORPORATE PROGRESSION

2013

2014

2015 +

TRANSFORMATION

FOUNDATION E&P LEADERSHIP

3 I BOAML ENERGY CONFERENCE 11/13/2014

APPLYING OUR BUSINESS STRATEGIES

• Balance capital expenditures with cash flow from operations • Divest noncore assets and noncore affiliates

• Develop world-class inventory • Target top-quartile operating and financial metrics • Pursue continuous improvement

• Reduce financial and operational risk and complexity

• Drive value leakage out of operations

• Achieve investment grade metrics

4 I BOAML ENERGY CONFERENCE 11/13/2014

3Q’14 OPERATIONAL AND FINANCIAL RESULTS

TOTAL ADJ. PROD.

11% YOY

(1)

726 mboe/d

ADJ. EARNINGS/FDS

(1) (2) (3)

LIQUIDS MIX to

29%

ADJ. OIL PROD.

5% Q/Q

of Total Production(2)

(1)

28% in 2Q’14

ADJ. EBITDA

12% YOY

7% YOY

$0.38(3)

$1.24 billion(3)

118.9 mbbls/d

CAPEX

8% YOY $1.35 billion

Adjusted for asset sales Oil and NGL collectively referred to as “liquids” 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

5 I BOAML ENERGY CONFERENCE 11/13/2014

CAPITAL DISCIPLINE (1)

$ in billions

$14.2

$7.6 ~$5.7

60%

36%

Decrease in Capital Investment

Increase in Operating Cash Flow

(2)

(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

6 I BOAML ENERGY CONFERENCE 11/13/2014

mmboe

Inventory Count

GROWING PRODUCTION WHILE MANAGING INVENTORY

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

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

• Adjusted production(3) for first nine months was 12% higher than year-ago levels (5)

• Achieved year-end estimated exit rate of 730 mboe/d in September, 2014 2014E % of E&P Capex by Play(2)(4)

2014E Avg. Operated Rig Count



• •

(1)

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

3Q‟14 avg. rig count

12 I BOAML ENERGY CONFERENCE 11/13/2014

UTICA ASSET OVERVIEW •

3Q‟14 avg. net production of ~86 mboe/d >

Up 27% sequentially

•

Averaged 7 operated rigs and connected 77 gross wells in 3Q‟14

•

Avg. completed well cost of ~$6.5 million(1) >

>1 million net acres 61% avg WI

Decreased 16% since 2012 amid increasing lateral lengths and frac stages CHK/TOT JV Outline CHK Operated Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

Production mix

(1)

As measured from Jan-July

13 I BOAML ENERGY CONFERENCE 11/13/2014

POWDER RIVER BASIN OIL GROWTH ENGINE •

388,000 net acres 79% avg WI

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

•

CHK Operated Rigs CHK Leasehold

Buckinghorse Plant (4Q'14) expected to add 120 mmcf/d processing capacity Production mix

•

Avg. completed well cost of ~$9.2

•

Multiple stacked formation tests in early 2015:

(1)

>

1 in Teapot

>

1 in Shannon

>

2 in Parkman

>

7 in Sussex

million(1)

As measured from Jan-July

14 I BOAML ENERGY CONFERENCE 11/13/2014

HAYNESVILLE ASSET OVERVIEW •

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

•

Up 11% sequentially

Averaged 9 operated rigs and connected 14

387,000 net acres 71% avg WI

gross wells in 3Q‟14 •

Avg. completed well cost of ~$8.2 million(1) Hayneville EUR performance (mboe) CHK Operated Rigs CHK Leasehold

Production mix

(1)

As measured from Jan-July

15 I BOAML ENERGY CONFERENCE 11/13/2014

HAYNESVILLE D&C IMPROVEMENT IMPACTS Haynesville Shale Well Cost Progress Report ($m) $4,000

$5,000

$6,000

$7,000

$8,000

$8,500

August 2013 Actual Reducing chemicals (FR/Gel)

$9,000 $10,000

ROR (%) $4.00/MCF 20% 8550

8350

Toe Prep Efficency Jan 2014 Well Cost Target Remove Resin Coated Proppant

$8,100

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

7950

$7.5 mm

7750

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

Increasing cluster/stg 7550

Manufacturing Mode

60%

8150

Ops Procedures (24 Hrs) Design Efficiencies / Rentals

40%

Drilling Efficiencies 2014 Mid-Year Results Non-Intervention Completion 2015 Target

34%

7150

Improvement in ROR for Drilling a Cross unit Lateral

$7,000 6950

Cross Unit Lateral Cross Unit 2015 Target

7350

$7,200

$7,500 6750

16 I BOAML ENERGY CONFERENCE 11/13/2014

REDUCING LEVERAGE ($mm) Term Loan

2012

2014E(1)(2)

$2,000

--

Long-Term Bonds

$10,666

$11,821

$418

--

$13,084

$11,821

VPPs

$3,187

$1,720

Operating & Finance Leases

$1,255

--

Subsidiary Preferred

$2,500

--

Corporate Preferred

$1,531

$1,531

$21,558

$15,061

Credit Facility

GAAP Debt

Total Adjusted Leverage

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

(1) (2)

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

17 I BOAML ENERGY CONFERENCE 11/13/2014

~10%

~30%

EXECUTING OUR PLAN

(1) (2)

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

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

18 I BOAML ENERGY CONFERENCE 11/13/2014

APPENDIX

19 I BOAML ENERGY CONFERENCE 11/13/2014

TRANSFORMING OUR BUSINESS

• Organizational structure • Decision rights • Focus on capital efficiency • Cash cost reduction

• Portfolio management and capital allocation process • Corporate budget process and plan

• Performance measurement and compensation program

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UPSIDE POTENTIAL

CHK

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NORTHERN MARCELLUS ASSET OVERVIEW •

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

•

Up 1% sequentially

Averaged 3 operated rigs and connected 23

gross wells in 3Q‟14 •

Avg. completed well cost of ~$7.0 million(2)

230,000+ net acres(1) 39% avg WI

Production mix(2)

(1) (2)

Excludes acreage off main development fairway As measured from Jan-July

22 I BOAML ENERGY CONFERENCE 11/13/2014

CHK Operated Rigs CHK Leasehold

MID-CONTINENT ASSET OVERVIEW •

3Q‟14 avg. net production of ~96 mboe/d

•

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

Miss. Lime Granite Washes CHK Leasehold CHK Operated Rigs

˃ Granite Wash plays(1) ˃

85,000 net acres

˃

83% avg WI, 67% avg NRI

Production mix(2)

˃ ~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) (2) (3)

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

23 I BOAML ENERGY CONFERENCE 11/13/2014

CURRENT HEDGE POSITION Natural Gas

Oil

72%

64%

42% Swaps

$4.50-$5.24/mcf NYMEX

$4.09/mcf NYMEX

$94.22/bbl NYMEX

26% Three-Way Collars

$4.11 - $4.37/mcf NYMEX

Natural Gas Hedges

Crude Oil Hedges

Q4 2014

Total 2015

Volume (bcf)

194

319

Price ($/mcf)

$4.12

$4.31

Volume (mmbls)

7,197

16,837

Price ($/bbl)

$94.22

$93.39

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

24 I BOAML ENERGY CONFERENCE 11/13/2014

UTICA DOWNSTREAM MARKETING ADVANTAGE •

Average transportation rates of $0.22 per mcf per day for balance of 2014

Dawn

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

Utica

Upper Midwest/Canadian Market Access >

•

200 MMcfd of capacity to Dawn market in 2017

Local Market Access >

Gulf Coast

96 MMcfd to local markets

25 I BOAML ENERGY CONFERENCE 11/13/2014

SENIOR NOTE PROFILE

Convertibles Other Senior Notes

Sr. Notes: $11.8 billion 9/30/2014 WACD – 5.0% Avg. Maturity: 5.2 years

$2,263

$1,800

$1,700

$1,500

$1,500 $1,100

$1,015

$396

$500

$0 2014

2015 2.75%(1)

(1) (2) (3)

2016 3.25%

2017 2.5%(1) 6.5% 6.25%(2)

2018 2.25%(1) 7.25%

2019 3mL+3.25%(3)

2020 6.875% 6.625%

2021

2022

2023

5.375% 6.125%

4.875%

5.75%

Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes Euro-denominated notes with a principal amount based on the exchange rate of $1.2631 to €1.00 at 9/30/2014 All-in yield composed of 3.25% spread and 3mL

26 I BOAML ENERGY CONFERENCE 11/13/2014

RECONCILIATION OF ADJUSTED EARNINGS PER SHARE ($ in mm, except per share data)

Three Months Ended:

9/30/2014

9/30/2013

$169

$156

(384) (9) 9 (54) 62 11 447

118 39 55 (82) (2) (2) -

$251

$282

43 3

43 3

Total adjusted net income attributable to CHK

$297

$328

Weighted average fully diluted shares outstanding(3)

776

765

$0.38

$0.43

Net income available to common stockholders Adjustments, net of tax: Unrealized losses on derivatives Restructuring and other termination costs Impairments of fixed assets and other Net gains on sales of fixed assets Net gains on sales of investments Provision for legal contingencies Other Redemption of preferred shares of a subsidiary(1)

Adjusted net income available to common stockholders(2) Preferred stock dividends Earnings allocated to participating securities

Adjusted earnings per share assuming dilution(2) (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. In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP

(3)

27 I BOAML ENERGY CONFERENCE 11/13/2014

RECONCILIATION OF ADJUSTED EBITDA ($ in mm)

Three Months Ended: Cash provided by operating activities Changes in assets and liabilities

Operating cash flow Net income

(1)

Interest expense Income tax expense Depreciation and amortization of other assets Natural gas, oil and NGL depreciation, depletion and amortization

EBITDA(2) Adjustments: Unrealized losses on natural gas, oil and NGL derivatives Restructuring and other termination costs Impairments of fixed assets and other Net gains on sales of fixed assets Net gains on sales of investments Net income attributable to noncontrolling interests Provision for legal contingencies Other

Adjusted EBITDA(3)

9/30/2014

9/30/2013

$1,184

$1,381

109

31

$1,293 $692

$1,412 $240

17 437 37 688

40 147 79 652

$1,871

$1,158

(622) (14) 15 (86) -(30) 100 2

191 63 89 (132) (3) (38) -(3)

$1,236

$1,325

(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.

28 I BOAML ENERGY CONFERENCE 11/13/2014

CORPORATE INFORMATION CHESAPEAKE 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 by phone at (405) 935-8870 or by email at [email protected]

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 #165167834/ #165167826 #U16450204/ #165167776/ #165167768 #U16450113/ #165167784/ #165167750 #165167107

CHK PrD

5.0% Cumulative Convertible Preferred Stock (Series 2005B) 5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock (Series A) Chesapeake Common Stock

29 I BOAML ENERGY CONFERENCE 11/13/2014

N/A N/A

N/A CHK