chesapeake energy investory presentation january 2014

January 2014 Investor Presentation

JANUARY 2014 INVESTOR PRESENTATION


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, anticipated asset sales, planned drilling activity and drilling and completion capital expenditures and other anticipated cash outflows, as well

as projected cash flow and liquidity, 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. Our ability to generate sufficient

operating cash flow to fund future capital expenditures is subject to all the risks and uncertainties that exist in our industry, some of which we may

not be able to anticipate at this time. Pending sales transactions are subject to closing conditions and may not be completed in the time frame

anticipated. Further, asset sales we are evaluating as we focus on our strategic priorities are subject to market conditions and other factors beyond

our control. Our plans to reduce financial leverage and complexity may take longer to implement if such sales are delayed or do not occur as

expected.

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, 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; current

worldwide economic uncertainty which may have 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; losses possible from pending or future litigation and regulatory investigations; cyber attacks adversely impacting our

operations; and the loss of key operational personnel or inability to maintain our corporate culture.

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, and we undertake no obligation

to update this information.

2


3Q’13 FINANCIAL RESULTS

3

(1) Includes unrestricted cash and borrowing availability under revolving credit facilities as of 9/30/2013

(2) Includes $3.6 billion of asset sales completed as of 9/30/2013 and ~$600 million of asset sales completed or under contract in 4Q’13

(3) Includes drilling and completion expenditures, leasehold and other

Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 26-27

22% YOY

$1.4 billion

OP. CASH FLOW

$5.2 billion(1)

LIQUIDITY YTD ASSET SALES TOTAL CAPEX

$4.2 billion(2) 57% YOY(3)

$1.5 billion

ADJ. EARNINGS/FDS

330% YOY

$0.43

ADJ. EBITDA

29% YOY

$1.3 billion


3Q’13 OPERATIONAL RESULTS

4

2% YOY

4.0 bcfe/d

TOTAL PRODUCTION LIQUIDS MIX OIL PRODUCTION

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

27% Up from 21% in 3Q’12

23% YOY

120 mbbls/d

NGL PRODUCTION

GAS PRODUCTION

of Total Production(1)

31% YOY

58.5 mbbls/d

10% YOY

3.0 bcf/d

to

3Q’13 total organic production growth rate of ~8% YOY, as adjusted for asset sales


GREAT FUTURE, GREAT ASSETS

5

Natural gas plays

Liquid plays

Wet-gas window

Operating states

Powder River Basin: Niobrara Shale

Anadarko Basin: Mississippi Lime

Anadarko Basin: Cleveland

and Tonkawa Tight Sands

Anadarko Basin: Texas

Panhandle Granite Wash

Anadarko Basin: Colony Granite Wash

OKC Headquarters Eagle Ford Shale

Utica Shale

Marcellus Shale

Barnett Shale

Haynesville/Bossier Shales

15.7 tcfe of proved reserves(1) 4.0 bcfe/d of production 13 mm net acres of leasehold

(1) Based on SEC pricing. Using 10-year average NYMEX strip prices as of 12/31/12, proved reserves were 19.6 tcfe


IMPROVING STATE OF CHESAPEAKE

Delivered strong third quarter results

› Full-year 2013 plan is on track

Implemented new strategy capitalizing on

CHK’s speed

Completed transformational review and

reorganization

› Implementing new operational processes to reduce

costs, increase efficiencies and enhance returns

› ~20% reduction in E&P workforce

Essential elements for success in place…

› Business units

› Capital allocation process

› Strategic metrics

› Performance management/compensation system

6

It’s a new day at CHK – we have reached an inflection point


KEY STRATEGIC TENETS

Financial discipline

› Balance capital expenditures with cash flow from

operations

› Competitive capital allocation process

› Divest noncore assets and noncore affiliates

› Reduce financial and operational risk and complexity

› Achieve investment grade metrics

7

Profitable and efficient growth from captured

resources

› Develop world-class inventory

› Target top-quartile operating and financial metrics

› Aggressively benchmark and post appraise our

performance

› Pursue continuous improvement

› Drive value leakage out of operations

› New play entry: substitution vs. addition


OUR FOCUS

Value-based vs. activity-based drilling program

› Core drilling, cost leadership and cycle time improvement

will add >$1 billion in PV10 per year

Balance sheet improvement

› Continue non-core asset sales program

Production growth in 2014 and beyond

› Decrease downtime and optimize base production

Reduce well costs and operating/overhead expenses

8


KEY NEAR-TERM VALUE INITIATIVES

Well cost reduction

› Enhances returns on core portfolio

› Builds additional economic inventory

Cycle time reduction

› 2013 avg. cycle time of ~8 months from spud to TIL

› Targeting improvement of 30-60%

Supply chain purchasing power

› CHK will no longer be a price taker

Optimizing iron – 40% rig count reduction YOY

› More efficient equipment/crews

Completion planning and optimization

9


FOCUSING CAPITAL ON CORE E&P OPERATIONS

10

$5.7

$13.2 $13.6 $13.4

$6.9

Devoting >80% capex to drilling and completion activities in 2013 vs. an average of ~50% during 2010-2012

59% 41% 55% 66% 82%

Drilling and Completion Capex Leasehold Capex

Other Capex Operating Cash Flow


Target our best rock – improve EURs and IPs

Capture drilling efficiency gains of 15 - 30%

by utilizing pre-existing pads and

implementing other cost-reduction initiatives

Optimize field development and

infrastructure

Right-size drilling program to capture

greatest value

NOW POSITIONED TO FOCUS ON EFFICIENCY

11

With HBP efforts largely complete, CHK has greater capital flexibility in 2014

Pad Drilling in Growth Plays


EAGLE FORD SHALE

12

Connected 100 wells to sales in 3Q’13 with an avg. peak daily rate of ~930 boe/d

788 producing wells and 117 wells WOPL or in various stages of completion(1)

HBP drilling largely complete: ~75% acres HBP’d in the core

~70% of wells drilling on existing pads in 2H’13E, anticipate ~85% in 2014

Currently operating ten rigs in the play; anticipate ramping to 15+ rigs in 2014

Oil window Wet-gas window Dry-gas window

3Q’13 Net Production: ~95 mboe/d CHK leasehold

Operated rigs

Industry rigs

68%

Oil

20%

Gas

12%

NGL

(1) As of 9/30/2013


EAGLE FORD GROSS OPERATED OIL PRODUCTION

13

CHK is the second-largest gross oil producer with the fastest growth rate in the Eagle Ford Shale

Data Source: IHS Energy

Chesapeake Peers


UTICA PRODUCTION ACCELERATING AS INFRASTRUCTURE EXPANDS

3Q’13 daily net production of ~165 mmcfe/d

› Up 91% sequentially

Connected 63 wells to sales in 3Q with an avg. peak daily rate of ~6.6 mmcfe/d

Drilled 377 wells in the Utica play as of 9/30

› Includes 169 producing wells, 208 WOPL or in various

stages of completion

Phase I of processing at Kensington (200 mmcf/d)

started 7/13; Phase II (200 mmcf/d) expected to

start up 12/13

ATEX ethane pipeline expected to start up 12/13

Currently operating nine rigs in the play

14 (1) CHK contracted facilities reflect plant capacity, not CHK’s contract volumes.

CHK contracted facilities

Third-party facilities

CHK leasehold

ATEX pipeline

CHK/TOT JV outline

Operated rigs

Industry rigs

Nisource/Hilcorp

Seneca

Cadiz

Leesville

Natrium

200 mmcf/d

Hastings

180 mmcf/d

Kensington

200 mmcf/d

OHIO

PENNSYLVANIA

WEST VIRGINIA


NORTHERN MARCELLUS

Connected 37 wells to sales in 3Q with an avg. peak daily rate of ~9.3 mmcfe/d

128 wells WOPL or in various stages of completion as of 9/30/13

Drilling program targeting EUR wells in excess of 10 bcfe gross

~65% of wells drilling on existing pads in 2H’13E; anticipate >80% in 2014

Currently operating five rigs in the play

Contracted >550 mmcf/d of new pipeline capacity in 4Q’13

15

CHK leasehold

CHK core

CHK core of the core

CHK operated rigs

Industry rigs

3Q’13 Net Production: ~825 mmcf/d


DAILY PRODUCTION

3% YOY

2012 3,886 bcfe/d

2013E 3,985 bcfe/d(3)

150% YOY

2012 $456 mm

2013E $1.14 billion(1)

ADJ. NET INCOME

NET WELLS TO SALES

ADJ. EBITDA

EXPECT TO DELIVER STRONG RESULTS IN 2013

16

15% YOY

2012 1,225 net wells

2013E 1,045 net wells

33% YOY

2012 $3.75 billion

2013E $5.0 billion(1)

48% YOY

2012 $13.4 billion

2013E $6.9 billion(2)

TOTAL CAPEX

OIL PRODUCTION

31% YOY

2012 31.3 mmbbls

2013E 41.0 mmbbls(3)

(1) 2013E projections assume NYMEX prices on open contracts of $3.50 to $3.75/mcf and $100.00/bbl. 2013E reconciliations on pages 24-25

(2) Total 2013E capex on page 9

(3) Based on the midpoint of 11/6/2013 Outlook on page 23

2013 efforts are leading to increased profitability


WHAT TO EXPECT GOING FORWARD?

Reduced capital intensity

Targets set on top-quartile operating metrics

Improved operational performance

Reduced financial leverage and complexity

improvement through noncore asset and affiliate

sales

2014 guidance to be provided in early 2014

17

Expect greater predictability, reduced risk and less complexity


CORPORATE INFORMATION

18

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CHESAPEAKE HEADQUARTERS

CORPORATE CONTACTS

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/CHESAPEAKEENERGY

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

mailto:[email protected]


APPENDIX


EMPHASIZING HIGHER-RETURN LIQUIDS-RICH PLAYS

20

Natural gas plays

Liquids-rich plays

0

20

40

60

80

100

120

140

Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14

Operated Rigs

0

25

50

75

100

125

150

175

200

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

Drilling and Completion Capex ($ in billions)

Average Operated Rig Count

% of Operated Drilling and Completion Capex

13% 10%

30%

46%

84% 86%

87% 90%

70%

54%

16% 14%

2008 2009 2010 2011 2012 2013E

Total Liquids Capex Total Dry Gas Capex

$0.38 $0.41 $0.35 $0.35

$0.39 $0.33

$0.23 $0.25 $0.25 $0.29

$0.94 $0.92

$0.88

$1.05 $0.97

$0.84

$0.83 $0.86

$0.78 $0.76

65%

27%

0%

10%

20%

30%

40%

50%

60%

70%

80%

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80Production expense ($/mcfe)

G&A ($/mcfe)

CHK Liquids % of Total Realized Revenue

CHK Liquids % of Total Production

(2)

(1) 4Q’13E assumes mid-point of full year 2013 drilling and completion costs in Outlook as of 11/6/2013

(2) Excluding stock-based compensation and restructuring and other termination benefits

(1)


LIQUIDS-DRIVEN PRODUCTION GROWTH

21

~178,000 bbls/d in 3Q’13

~3.0 bcf/d in 3Q’13

E

% L

iqu

ids

Miss Lime, N. Eagle Ford, Haynesville and other asset sales

Chesapeake’s dry-gas production peaked in mid-2012. Associated natural gas and liquids are now driving production growth.


2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Term Loan

Convertibles

Other Sr. Notes

SENIOR NOTE PROFILE(1)

22

$1,660

$4,294

$1,112

$1,800

$1,100

$650

$1,700

2.75%(2) 3.25% 5.75%(3) 2.25%(2) 6.625%(4) 6.875% 5.375% 5.75%

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

6.5% 6.875%

6.25%

$500

Rates

($ in MM)

(1) As of 9/30/2013 (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) COO $650 mm Senior Notes due 2019

Average

Interest Rate:

5.9%

Sr. Debt and

Term Loan:

$12.8 Billion

Average

Maturity:

5.1 years

Strong liquidity profile: ~$5.2 billion of liquidity as of 9/30/2013


OUTLOOK SUMMARY(1)

23

(1) As of 11/6/2013 (2) Assumes NYMEX prices on open contracts of $3.50 to $3.75/mcf and $100.00/bbl in 2013 (3) Excludes expenses associated with stock-based compensation and restructuring and other termination benefits (4) Before changes in assets and liabilities.

2012 2013E

Natural gas (bcf) 1,129 1,080 – 1,090

Oil (mbbls) 31,265 40,000 – 42,000

NGL (mbbls) 17,615 20,000 – 21,000

Natural gas equivalent (bcfe) 1,422 1,440 – 1,468

YOY production increase (adjusted for planned asset sales) 19% 3%

Natural gas production increase (decrease) 12% (4%)

Liquids YOY production increase 54% 26%

% production from liquids 20% 25%

% realized revenues from liquids(2) 59% 63%

Operating costs per mcfe:

Production expense, production taxes and G&A(3) $1.38 $1.20 – $1.35

Operating cash flow ($mm)(2)(4) $4,053 $5,050 – $5,100

Drilling and completion costs on proved and unproved

properties ($mm) ($8,831) ($5,500 – $5,800)

Acquisition of unproved properties, net ($mm) ($1,718) ($200 – $250)


RECONCILIATION OF 2013 FINANCIAL PROJECTIONS: ADJUSTED EBITDA TO OPERATING CASH FLOW

24 (1) Includes effects of estimated realized hedging gains and losses and excludes effects of unrealized hedging gains and losses (2) Includes expense related to stock-based compensation, but excludes restructuring and other termination benefits (3) Before changes in assets and liabilities

NYMEX Natural Gas Prices

As of 11/6/2013 Outlook ($ in mm; oil at $100 NYMEX) $3.00 $4.00 $5.00 O/G revenue (unhedged) $6,820 $7,000 $7,190

Hedging effect(1) (30) (170) (300)

Marketing, service operations and other 260 260 260

Production taxes ~4% (230) (240) (240)

Production cost (LOE) (1,200) (1,200) (1,200)

G&A(2) (470) (470) (470)

Net income attributable to noncontrolling interests (180) (180) (180)

Adjusted ebitda $4,970 $5,000 $5,060

Interest expense incl. capitalized interest (180) (180) (180)

Noncash interest expense 80 80 80

Stock-based compensation 90 90 90

Restructuring and other termination benefits (70) (70) (70)

Net income attributable to noncontrolling interests 180 180 180

Operating cash flow(3) $5,070 $5,100 $5,160


RECONCILIATION OF 2013 FINANCIAL PROJECTIONS: OPERATING CASH FLOW TO ADJUSTED NET INCOME

25 (1) Before changes in assets and liabilities

NYMEX Natural Gas Prices

As of 11/6/2013 Outlook ($ in mm; oil at $100 NYMEX) $3.00 $4.00 $5.00

Operating cash flow(1) $5,070 $5,100 $5,160

Oil and gas depreciation (2,540) (2,540) (2,540)

Depreciation of other assets (330) (330) (330)

Income taxes (38% rate) (800) (810) (830)

Noncash interest expense (80) (80) (80)

Stock-based compensation (90) (90) (90)

Restructuring and other termination benefits 70 70 70


Adjusted net income attributable to Chesapeake $1,120 $1,140 $1,180

Adjusted earnings per fully diluted share $1.47 $1.50 $1.55


RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

26

(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: 9/30/2013 6/30/2013 9/30/2012

Net income (loss) available to common stockholders $156 $457 $(2,055)

Adjustments, net of tax: Unrealized (gains) losses on derivatives 118 (325) 63

Net (gains) losses on sales of fixed assets (82) (68) 4

Impairment of natural gas and oil properties _ _ 2,022

Impairments of fixed assets and other 55 143 23


(Gains) losses on sales of investments (2) 6 (19)

Losses on purchases of debt _ 44 _

Premium on purchase of preferred shares of a subsidiary _ 69 _

Other (2) 3 (5)

Adjusted net income available to common stockholders(1)

$282 $334 $35

Preferred stock dividends 43 43 43

Earnings allocated to participating securities 3 11 _

Total adjusted net income $328 $388 $78

Weighted average fully diluted shares outstanding(2) 765 763 754

Adjusted earnings per share assuming dilution(1) $0.43 $0.51 $0.10


RECONCILIATION OF OPERATING CASH FLOW, EBITDA AND ADJUSTED EBITDA

27

(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: 9/30/2013 6/30/2013 9/30/2012

Cash provided by operating activities $1,356 $1,281 $949 Changes in assets and liabilities 12 89 169

Operating cash flow(1)

$1,368 $1,370 $1,118

Net income $240 $625 $(1,971)

Interest expense 40 104 36

Income tax expense (benefit) 147 384 (1,260)

Depreciation and amortization of other assets 79 76 66

Natural gas, oil and NGL depreciation, depletion and amortization 652 645 762

EBITDA(2)

$1,158 $1,834 $(2,367)

Adjustments: Unrealized (gains) losses on natural gas, oil and NGL derivatives 191 (576) 104

Impairment of natural gas and oil properties _ _ 3,315

Net (gains) losses on sales of fixed assets (132) (109) 7

Impairments of fixed assets and other 89 231 38


(Gains) losses on sales of investments (3) 10 (31)

Losses on purchases of debt _ 70 _


Other (3) 2 (4)

Adjusted EBITDA(3) $1,325 $1,424 $1,024

chesapeake energy investory presentation january 2014

News & Politics