Investor Presentation

1 INVESTOR PRESENTATION 3-24-14

INVESTOR PRESENTATION LAST UPDATED 3-24-14


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 those 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 and drilling and completion capital expenditures, as well as projected cash flow, business

strategy and other plans and objectives for future operations.

• Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information

as of a specific date, and such 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.

• Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2012

annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2013. 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 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; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could

adversely affect our revenues and cash flow; losses possible from pending or future litigation and regulatory investigations; and cyber attacks

adversely impacting our operations.

• Although we believe the expectations and forecasts reflected in 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. We

caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation or as otherwise

indicated, and we undertake no obligation to update this information, except as required by applicable law.


KEY STRATEGIC TENETS

• Financial discipline

˃ 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

• Profitable and efficient growth from captured

resources

˃ Develop world-class inventory

˃ Target top-quartile operating and financial metrics

˃ Pursue continuous improvement

˃ Drive value leakage out of operations


Powder River Basin: Niobrara Shale

Mid-Continent: Mississippian Lime

Mid-Continent: Cleveland

and Tonkawa Tight Sands

Mid-Continent: Colony Wash and

Texas Panhandle Granite Wash

Eagle Ford Shale

Utica Shale

Marcellus

Shale

Barnett Shale

Haynesville Shale

OPERATING AREAS


ADJUSTED PRODUCTION GROWTH

Oil (mmbbls) 41.1 (2.6) 38.5 8 – 12%

NGL (mmbbls) 20.9 (0.5) 20.4 44 – 49%

Natural Gas (bcf) 1,095 (60) 1,035 4 – 6%

Total (mmboe) 244.4 (13.1) 231.4 8 – 10%

2014E Adjusted

Production Growth

2013 Reported

Production

2013

Asset

Sales

2013 Adjusted

Production

5

2013 Asset Sale Adjustments (mmboe)

249 - 253

2014E

Production

2013

Adjusted

Production

(4.8) (3.6)

(3.5) (1.2)

231

244

2013

Reported

Production

N. Eagle Ford Haynesville Miss. Lime JV Marcellus


Oil, NGL and associated natural gas from liquids plays continue to drive production growth; 25% CAGR in Liquids from 2010 - 2014

NGL

Oil

Assoc. Natural Gas

Dry Shale Gas

Conventional Natural Gas

PRODUCTION PROFILE


CAPITAL DISCIPLINE

2014 total capital expenditures expected to range from $5.2 – $5.6 billion; planned reduction of >20% YOY and ~60% compared to 2010-12 average

(1) Based on midpoint of company issued Outlook range provided on 2/6/2014

(1)


CASH COST DISCIPLINE

(1)

(1) Excluding share-based compensation


• 2014E total capital expenditures expected to range from $5.2 – $5.6 billion,

E&P capex 90%-95%

• Capturing substantial supply chain management efficiencies

• Continuous investment high grading and post appraisal process

2014 CAPITAL ALLOCATION

E&P Capex by Play(1)

(2)

<5% <5%

~

~ ~

~

~

~

~80%

~20%

Liquids

Gas

E&P Capex by Product(1)

(1) Net of $596 mm and $135 mm drilling carries remaining at 12/31/2013 in the Utica and PRB, respectively; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest


EAGLE FORD GROSS OPERATED OIL PRODUCTION

Chesapeake Peers

Data Source: IHS Energy


Avg. Well Cost ($ in mm)

% Multi-well Pad Drilling Spud to Spud Cycle Times (days)

• Focused on continuous improvement

˃ Cycle time improvement of >20% in 2014

˃ >95% multi-well pad drilling utilization in 2014

˃ Targeting further well cost improvement

• Plan to average 15 - 18 operated rigs in 2014

EAGLE FORD


EAGLE FORD TRAJECTORY

• Maximizing investment efficiency

˃ Short-term rig reduction to develop inventory

˃ Future drilling approximately a 1:1 ratio of spuds to TIL

˃ Short-term reduction in oil volume growth during transition

(1)

(1) Volumes on secondary vertical axis not disclosed

Op

era

ted

Ne

t O

il P

rod

ucti

on


MID-CONTINENT

• Includes Mississippian Lime,

Cleveland/Tonkawa and Granite Wash

˃ ~2.5 mm net acre position, largely HBP

˃ Multiple stacked pay targets

• ~7% decrease in D&C YOY

• ~15% reduction in LOE YOY(1)

• Spud to 1st sales cycle time down ~30% YOY

(1) Controllable LOE (excludes Taxes and Insurance)

Meramac

.

.

.

.

.

.

Mississippian Lime

DES

MOINESIAN

A - E ZONES

HOGSHOOTER

U. CLEVELAND

L. CLEVELAND

LANSING

ATOKA

A – C ZONES

SPRINGER

Des

Moines

Granite

Wash

Cleveland/Tonkawa and Granite Wash

Program Efficiency vs. Rig Count

2009 2010 2011 2012 2013


UTICA

• Largest and most experienced operator

˃ Drilled more than 450 wells to date

˃ Improvement in EURs and PV through completion

design optimization

• Growing processing capacity to drive production

• Plan to average 7 - 9 operated rigs

• Recently drilled 2 wells in 8 days

Spud to Rig Release Cycle Times (days)

% Multi-well Pad Drilling Total Gross Processing Capacity (mmcf/d)


Net Production (mmcf/d)

MARCELLUS NORTH

• Continue to set production records

˃ Dec’13 net production ~845 mmcf/d

• 2014 development plan targeting EURs

>10 Bcf and ROR >100%

• Plan to average 6 - 7 operated rigs in 2014

Rate of Return % Multi-well Pad Drilling


HAYNESVILLE SHALE

• 570,000 gross acres delineated and HBP

˃ Industry-leading position in the core

• ~700 operated producing wells

• More than 550 drill site pads constructed

• ~4,500 well inventory on 80 acre spacing

• Sufficient pipeline and takeaway capacity in place

• 2014 focus is on high-return, low-risk locations

˃ 100% multi-well pad drilling utilization

˃ Gross EUR type curve of ~9 bcfe

˃ Plan to average 7 - 9 operated rigs

• 2 recent wells drilled and completed for ~$7.0 mm

Rate of Return

Targeted Range:

Avg. Well Cost ($ in mm)


NEAR-TERM PRIORITIES

• Capital Efficiency

• Balance Sheet Improvement

• Cash Flow Growth

Analyst Day: May 16th, 2014 - Oklahoma City, OK


APPENDIX


41 - 48 Liquids Focused Rigs

14 - 17 Natural Gas Focused Rigs

55 - 65 Total Operated Rigs

OPERATIONS

2013 Year-End Drilled Well Inventory (Gross Op’d)

4Q’13 Daily Avg. Net Production (mboe/d) 2014E Avg. Operated Rig Count

(1) Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays

(1)

(1)


2013 FINANCIAL RESULTS

(1) Includes unrestricted cash and borrowing availability under revolving credit facilities as of 12/31/2013

(2) Includes ~$235 mm of expenditures in 4Q’13 to purchase rigs and compressors subject to sale-leaseback arrangements

Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 22-23

PROD. and G&A EXP.

$4.9 billion(1)

LIQUIDITY 2013 ASSET SALES TOTAL CAPEX

$ 4.4 billion 49% YOY

$6.7 billion(2)

ADJ. EARNINGS/FDS

146% YOY

$1.50

ADJ. EBITDA

34% YOY

$5.0 billion

15% YOY

$6.36/boe


2013 OPERATIONAL RESULTS

3% YOY

244 mmboe

TOTAL PRODUCTION LIQUIDS MIX OIL PRODUCTION

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

25% 20% in 2012

32% YOY

112.6 mbbls/d

NGL PRODUCTION

PROVED DEVELOPED

of Total Production(1)

19% YOY

57.2 mbbls/d

68%

57% in in 2012

Adjusted for asset sales, 2013 total production increased ~11% YOY

PROVED RESERVES

2% YOY

2.7 Bboe

of Proved Reserves to

to


($mm) 12/31/2012 12/31/2013

Unrestricted cash $287 $837 +$550

Working capital(1) ($3,605) ($2,696) +$909

Other long-term liabilities(2) $1,176 $984 +$192

Long-term debt, net of disc. $12,157 $12,886 -$729

Total improvement +$922

Net debt/adj. ebitda(3) 3.3x 2.4x

Net debt/total capitalization(3)(4) 41% 40%

Net debt/proved reserves(3)(5) $4.72/boe $4.50/boe

(1) Excludes unrestricted cash (2) Excludes deferred income taxes, long-term derivative liabilities and asset retirement obligation (3) Net debt is total debt net of unrestricted cash; adjusted ebitda is non-GAAP measurement, reconciliation found on pages 26-27 (4) Total capitalization includes net debt, preferred stock, noncontrolling interests, common stock and other stockholders’ equity (5) Proved reserves based on SEC recognized standard trailing 12 month average NYMEX strip prices as of 12/31/2012 and 12/31/2013

BALANCE SHEET IMPROVEMENT

Additional cash use of ~$450 mm includes ~$210 mm to repurchase preferred shares of CHK Utica, L.L.C. and ~$240 mm for certain drilling rig and compression operating leases


2014 HEDGES

(1) Hedged positions as of 1/31/2014 based on production estimates provided in 2/6/2014 Outlook; 21% of 2014 gas production is hedged under collar arrangements with upside to average NYMEX price of $4.38/mcf and exposure below average NYMEX price of $3.54/mcf

58%

Natural Gas Oil

$93.92/bbl

NYMEX

68%

47%

Swaps 21%

Collars

$4.09 - $4.38/mcf

NYMEX

$4.18/mcf

NYMEX


OUTLOOK SUMMARY

(1) Growth ranges based on midpoint of company issued Outlook issued on 11/6/2013 (2) Assumes ethane recovery in Utica and southern Marcellus to fulfill CHK’s pipeline commitments, no ethane recovery in Rockies, minimal ethane recovery in Eagle Ford and partial ethane

recovery in Mid-Continent (3) Assumes average NYMEX prices on open contracts of $4.00/mcf and $90.00/bbl in 2014 and includes expected settlements for commodity derivatives adjusted for option premiums;

settlements are reflected in the period of original contract expiration for derivatives that are closed early (4) Excludes expenses associated with share-based compensation and restructuring and other termination costs (5) Before changes in assets and liabilities, a non-GAAP financial measure

2014E

Absolute production growth(1)

:

Liquids 14 – 18%

Oil 1 – 5%

NGL(2) 40 – 45%

Natural gas (2) – 0%

Total production 2 – 4%

Daily rate (mboe) 680 – 695

% of production mix from liquids 29%

% O/G revenues from liquids(3) 62%

Operating costs per boe:

Production expenses, production taxes and G&A(4) $6.30 – $7.10

Operating cash flow ($mm)(3)(5) $5,100 – $5,300

Total capital expenditures ($mm) $5,200 – $5,600

24


SENIOR NOTE PROFILE

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Term Loan

Convertibles

Other Sr. Notes

$1,660

$4,301

$1,112

$1,800

$1,100

$650

$1,700

2.75%(2) 3.25% 5.75%(3) 2.25%(2) 6.625%(5) 6.875% 5.375% 5.75%

9.5% 2.5%(2) 7.25% 6.625% 6.125%

6.5% 6.875%

6.25%(4)

$500

Rates:

($ in MM)

(1) Principal balances as of 12/31/2013 (2) Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes (3) Interest at LIBOR plus 4.50%; LIBOR rate is subject to a floor of 1.25% per annum (4) Euro-denominated notes with a principal amount based on the exchange rate of $1.3743 to €1.00 at 12/31/2013 (5) COO $650 mm Senior Notes due 2019

Average

Interest Rate:

5.9%

Sr. Debt and

Term Loan:

$12.8 Billion(1)

Average

Maturity:

4.9 years

Strong liquidity profile: ~$4.9 billion of liquidity as of 12/31/2013


(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)

Twelve Months Ended: 12/31/2013 12/31/2012

Net income (loss) available to common stockholders $474 ($940)

Adjustments, net of tax: Unrealized gains on derivatives (100) (347)

Restructuring and other termination costs 154 4

Impairments of natural gas and oil properties – 2,022

Impairments of fixed assets and other 341 208

Net gains on sales of fixed assets (187) (163)

(Gains) losses on investments 95 (622)

Losses on purchases of debt and extinguishment of other financing 120 122

Other (1) 1

Adjusted net income available to common stockholders(1) $896 $285 Preferred stock dividends 171 171

Premium on purchase of preferred shares of a subsidiary 69 –

Earnings allocated to participating securities 10 –

Total adjusted net income attributable to CHK $1,146 $456

Weighted average fully diluted shares outstanding(2) 765 755

Adjusted earnings per share assuming dilution(1) $1.50 $0.61

RECONCILIATION


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)

Twelve Months Ended: 12/31/2013 12/31/2012

Cash provided by operating activities $4,614 $2,837 Changes in assets and liabilities 342 1,083

Operating cash flow(1)

$4,956 $3,920

Net income (loss) $894 ($594) Interest expense, net of unrealized gains 227 77

Income tax expense (benefit) 548 (380)

Depreciation and amortization of other assets 314 304

Natural gas, oil and NGL depreciation, depletion and amortization 2,589 2,507

EBITDA(2)

$4,572 $1,914

Adjustments: Unrealized (gains) losses on natural gas, oil and NGL derivatives (228) (561)

Restructuring and other termination costs 248 7

Impairment of natural gas and oil properties – 3,315

Impairments of fixed assets and other 546 340

Net gains on sales of fixed assets (302) (267)

Losses on investments 146 –

(Gains) losses on sales of investments 7 (1,019)

Losses on purchases of debt and extinguishment of other financing 193 200

Net income attributable to noncontrolling interests (170) (175)

Adjusted EBITDA(3) $5,012 $3,754


PUBLICLY TRADED SECURITIES CUSIP TICKER

9.5% Senior Notes due 2015 #165167CD7 CHK15K

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

6.875% Senior Notes due 2018 #165167CE5 CHK18B

7.25% Senior Notes due 2018 #165167CC9 CHK18A

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

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

CORPORATE INFORMATION

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CHESAPEAKE HEADQUARTERS

GARY T. CLARK, CFA Vice President — Investor Relations and Research

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]

TWITTER.COM/CHESAPEAKE FACEBOOK.COM/CHESAPEAKE YOUTUBE.COM/CHESAPEAKE

CORPORATE CONTACTS

mailto:[email protected]

Investor Presentation

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