Howard Weil 2016 final

HOWARD WEIL CONFERENCEMarch 22, 2016

2HOWARD WEIL CONFERENCE

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. They include statements that give our current expectations or forecasts of future events, production and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, capital expenditures, expected efficiency gains, our ability to improve margins, reduce operating and G&A expenses, optimize base production, the timing of anticipated asset sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other opportunities, plans and objectives for future operations (including restructuring of midstream gathering agreements), and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

• Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; write-downs of our oil and natural gas carrying values due to declines in prices; the limitations our level of indebtedness may have on our financial flexibility; the availability of operating cash flow and other funds to finance reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event; our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means; and our inability to access the capital markets on favorable terms or at all.

• In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law.

HOWARD WEIL CONFERENCE 3

EARLY 2016 ACCOMPLISHMENTS

2016> ~$700 million in asset divestitures closed or under signed PSA

• Exceeded previously disclosed 1Q’16 target of $200 – $300mm• Line of sight on additional $500 – $1,000mm in asset divestitures in 2016

> Planned 2016 total capital expenditures of $1.3 to $1.8 billion; ~57% reduction YOY (1)

> Projected 2016 production decline of 0% to 5%, adjusted for asset sales

> Transportation contracts renegotiated for a $50mm reduction in shortfall payments

> ~$4.3 billion in liquidity in cash and undrawn revolver (2)

(1) Includes capitalized interest. (2) As of February 23, 2016.


CHESAPEAKE’S FOCUS IN 2016WHAT WE PLAN TO DO

Maximize Liquidity□ Reduce capital budget by >50%□ 10% reduction in LOE/boe□ 15% reduction in G&A/boe (1)

Optimize Portfolio

□ Close on $700mm in signed asset divestitures

□ $500 – $1,000mm in additional asset divestitures

□ Fund short-cycle cash generating projects

Increase EBITDA□ Improve gathering and transportation

agreements□ 2016 capital program focusing on TILS□ Reduce base decline rate by 10%

Debt Management/Elimination

□ Proactive liability management□ Open market repurchases of debt□ Focus on 2017 and 2018 maturity

management(1) Includes stock-based compensation.


2016 CAPITAL ALLOCATION

• 2016 program provides attractive return on incremental capital and optimizes commitments

• Anticipated full access to revolver

D&C BreakoutFunding short-cycle cash generating

projects to maximize EBITDA

Drilling 45%

Completion 55%

2015

2016E

(1) Includes other exploration and development costs and PP&E.

Drilled Uncompleted (DUC) Inventory

Focusing spend on completions to reduce inventory

2015

480

2016E

225 – 250

2016 Capital BudgetDecreasing capital budget by ~57%

2015

2016E

$3.0BD&C

~$3.6B

$1.3 – $1.8B

(1)

(1)

$0.8 – 1.3BD&C

$0.2B Other

$0.3B Cap Int.

$0.4B Cap Int.

$0.2B Other

Drilling 30%

Completion 70%


ATTRACTIVE ROR FROM INVENTORY PROGRAM

Inventory (1) Gross Investment

GrossEUR / well ROR (2)

Eagle Ford Shale 145 – 155 ~ $350mm ~ 525 mboe 20% – 30%

Haynesville Shale (3) 20 – 30 ~ $75mm ~ 11 bcf 70% – 80%

Utica Shale 45 – 55 ~ $55mm ~ 1,470 mboe 70% – 80%

Short cycle return on capital

Inventory reduction program yields strongest return per dollar invested~50% of development budget allocated toward inventory reduction

2 0 1 6 I n v e n t o r y P r o g r a m

(1) Inventory well defined as DUC or completed waiting to TIL.(2) Pricing assumptions: 2016: $36/$2.18, 2017: $41/$2.62, 2018: $44/$2.69, 2019: $46/$2.73, 2020+: $48/$2.82.(3) Firm transport modeled as sunk cost.

HOWARD WEIL CONFERENCE

Marcellus Shale130 mboe/d net (1)

Spud: 0-5 / TIL: 20Utica Shale (2)

148 mboe/d net (1)

Spud: 0-5 / TIL: 45-55

Barnett Shale70 mboe/d net(1)

Spud: 0 / TIL: 5

Eagle Ford Shale97 mboe/d net (1)

Spud: 20-30 / TIL: 170-180

Powder River Basin20 mboe/d net (1)

Spud: 0 / TIL: 5

Mid-Continent94 mboe/d net (1)

Spud: 40-50 / TIL: 35-45

Haynesville Shale102 mboe/d net (1)

Spud: 25-35 / TIL: 50-60

VAST U.S. ONSHORE ASSET PORTFOLIOSIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE

7

2016 D&C Asset Funding

Haynesville32%

Marcellus6%

Utica6%

Other1%

Eagle Ford Shale33%

STACK/Mid-Con

22%

(1) Average daily production 4Q’15.(2) Includes production volumes from legacy Devonian wells in West Virginia and Kentucky (~8 mboe/d net).

~8.1mm net acres in developed & undeveloped leasehold


RECORD OF CONTINUOUS IMPROVEMENT

(1) Production range and total capital expenditure guidance from 2/24/16 outlook. Includes capitalized interest.(2) Production cost and net G&A guidance from 2/24/16 outlook. (3) Includes stock-based compensation.(4) Historical capital spend, debt principal, and operating costs contain Seventy Seven Energy data.

2012 2013 2014 2015 2016 E

$7.76$6.60

$5.93$5.17

Operating Costs

Production cost ($/boe) Net G&A ($/boe)

2012 2013 2014 2015 2016 E

648 670 706 679605 - 635

$14.7 $7.8$6.7

$3.6

Production (mboe/d) CapEx ($B)

Production

(3)2012 2013 2014 2015 2016 E

$13.1 $13.2$11.8

$9.7

Debt Principal $B

› Resilient production despite substantial reductions in capital expenditures

› Continued improvement expected in 2016

(1)

(2)$4.30 - $4.70

$1.3 - $1.8(1)

Continued

progress in ‘16

(4)

(4)

(4)


CONTINUOUS IMPROVEMENT IN CAPITAL EFFICIENCY

(1) Data represents average net D&C $ / net EUR in boe, grouped by TIL year.

2012 2013 2014 2015 2016 E

$19

$13

$7 $6

Haynesville Shale

68%

2012 2013 2014 2015

$22$18

$14 $14

Mid-Continent

37%

2012 2013 2014 2015 2016 E

$26$21

$15 $17

Eagle Ford Shale

34%

2012 2013 2014 2015

$9$8

$6 $5

Marcellus Shale

47%

2012 2013 2014 2015

$18

$10 $9 $8

Utica Shale

56%

Continually improved F&D cost across the portfolio(1)

Significant improvements forecasted for 2016


STACKED STRONG IN THE MID-CONTINENTINDUSTRY LEADING MID-CONTINENT PRODUCER

10

• Robust economics early in the play delivering top-tier returns with further upside potential (1)

• Planning 2 – 3 rigs in 2016 for appraisal and development

• Industry leading cost and drilling performance

(1) Pricing assumptions: 2016: $36/$2.18, 2017: $41/$2.62, 2018: $44/$2.69, 2019: $46/$2.73, 2020+: $48/$2.82(2) Oswego Top Performer: Hughes Trust 33-18-7 1H actual production with type curve capex. Meramec Top Performer: Wittrock 16-169 1H actual production and actual capex.

Mer

amec

Osw

ego

Undiscounted Payout 2.1 yr 0.8 yrsRate of Return 39% >230%PV10 Breakeven Oil Price

$31/bo $22/bo

Undiscounted Payout 3.4 yrs 1.2 yrsRate of Return 23% >100%PV10 Breakeven Oil Price

$34/bo $20/bo

Type Curve

Top Performer

(2)

Wittrock 16-16-9 1H

1,164 BOPD3,144 MCFPD

Rouce 4-17-10 1H

594 BOPD 876 MCFPD

OSWEGO PLAY

MERAMECPLAY

New well currently flowing back IP is 30 day avg production

Stangl 36-16-9 1H

1,161 BOPD1,316 MCFPD

Luber 28-18-7 1H

15 days online440 BOPD

221 MCFPD Hughes Trust 33-18-7 1H

1,239 BOPD486 MCFPD

Meritt 12-18-6 1G

15 days online426 BOPD

972 MCFPD


0 20 40 60 80 100 120 140 160 1800

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Days Producing

Cum

ulat

ive

Prod

uctio

n, B

OE

Expansive unconventional experience and strong acreage position delivering robust early Meramec results

STRONG EARLY MERAMEC RESULTS

Chesapeake Operated (1)

Competitor Operated (2)

(1) Represents three Chesapeake operated wells.(2) 45 competitor wells. 2-mile multi-section laterals within the over-pressure oil window. Combination of state reported monthly volumes and non-operated daily

production data.


EAGLE FORD SHALEENHANCED ECONOMICS AND EFFICIENCIES

(1) Pricing assumptions: 2016: $36/$2.18, 2017: $41/$2.62, 2018: $44/$2.69, 2019: $46/$2.73, 2020+: $48/$2.82.(2) Normalized to 6,500’ lateral length.

Drilling Cycle Time and Total Measured Depth

• Projected 2016 well cost of $4.2mm

• High-graded core position held with 20-30 new wells in 2016 delivering a positive return

• Inventory TILs delivering 20% – 30% ROR (1)

• Significant field-wide efficiency gains driving ROR higher

Average Well Cost

2012 2013 2014 2015 2016E0

5

10

15

20

25

14,000

14,500

15,000

15,500

16,000

16,500

17,000

1715 13 12

11

Cycle Time Avg. Total Measured Depth

$ in

milli

ons

Drilli

ng D

ays

Mea

sure

d De

pth

(ft.)

2012 2013 2014 2015 2016E$0

$2

$4

$6

$8

$10$8.1

$6.9$5.9 $5.4

$4.2(2)


• Significant productivity uplift due to CHK optimized completions

• Continued focus on field-wide extended lateral development

0 6 12 18 240

5001,0001,5002,0002,5003,0003,5004,000

Legacy Field Completions CHK Optimized Completions

Cum

ulati

ve P

rodu

ction

(Mcf

)

4,500' Traditional 5,150' Modern 7,500' Extended Lateral

10,000' Extended Lateral

$2.26

$1.62

$1.32$1.12

4,500’5,150’

7,500’ 10,000’

Well Cost/Lateral Ft ($1,000/ft) Lateral Length (ft)

HAYNESVILLE SHALECONTINUOUS IMPROVEMENT IN A MATURE ASSET

13

Completion Enhancements Increasing Productivity

Months

50%

2016E: 8,000’ avg. LL

70% CompleteWill satisfy 70% of drilling commitment with Williams by year-end

Extended Lateral Efficiency Advantage

• Optimized 2016 program capitalizes on recent improvements in midstream contracts

Tighter cluster spacing, higher proppant volumes and enhanced subsurface targeting driving productivity higher

Commitment Satisfied, 70%

Commitment Remaining, 30%


2015 20162Q 3Q 4Q 1Q 2Q

Sale of CHK Cleveland Tonkawa

Haynesville and Utica Midstream Contract Renegotiations

Second Lien Debt Exchange

Announced $700 Million in Asset Divestitures

Continue Maximizing Liquidity, Increasing EBITDA and Reducing Debt

Eliminated preferred and ORRI obligations

Enhanced margins and added flexibility

Reduced total debtby ~$2.1 billion; GAAP debt below $10 billion for first time since 2006

Exceeded previously disclosed target of $200 – $300 million

Renegotiated GP&T rates in place; repurchase debt in open market; targeting additional $0.5 – $1.0 billion in asset sales in 2016

THE TRANSFORMATION CONTINUES

We are focused on maximizing liquidity, optimizing the portfolio through asset sales, increasing EBITDA through contract negotiations and proactively reducing debt maturities to strengthen the balance sheet.

15

APPENDIX


9/30/15 Outstanding 3/16/16 Outstanding$0

$500

$1,000

$1,500

$2,000

$2,500

$382 $336

$660

$380

$1,168

$902

6.25% 2017 6.5% 2017 2.5% 2037

$ M

M

(1) 6.25% 2017's converted to USD for entire period using exchange rate of $1.1108 to €1.00.(2) Incremental liquidity savings includes principal savings and net interest impact.

27% REDUCTION IN 2017 MATURING/PUTTABLE DEBTPROACTIVE LIABILITY MANAGEMENT


Reduced 2017 maturing/puttable debt obligations by $594 million since 9/30/15

$2,211

$1,617 (1)

$485mm Total incremental liquidity since 9/30/2015 through proactive liability management (2)

Incremental Liquidity

Debt Exchange $305 million of new 2nd lien $291 million

Open Market Repurchases $99 million of cash $86 million

Equity for Debt Exchanges

17.3 million shares (valued at $73 million) $108 million

Financial Transaction


2015 2016 2017 2018 2019 2020 2021 2022 2023$2

$1,617

$878$1,104 $1,126

$876

$3,064

$384$394 $500

$594

$137

$396$674

$824

$861

$716

(1) Amounts are pro-forma for 2016 liability management transactions (cash repayment of maturing debt, OMRs and 3(a)(9) debt for equity exchanges) through 3/18/16 and assume euro-notes are converted to USD at 3/14/16 exchange rate of $1.1108 to €1.00.

(2) Recognizes earliest investor put option as maturity for the 2.50% 2037 and 2.25% 2038 Contingent Convertible Senior Notes.(3) Reflects amount that was not put to the company in 2015; next investor put date is 2020.

MATURITY PROFILEPROACTIVE LIABILITY MANAGEMENT (1)

2015 Debt Reduction

Liabilities(2)

(3)


IMPROVING AND REBALANCING MIDSTREAM COMMITMENTS

• Recently executed agreements in the Haynesville, Barnett and Eagle Ford˃ Forecasted to improve cash flow by $50mm in 2016 and $50mm in 2017

with no additional drilling commitments

• Actively marketing unutilized portion of transportation to increase utilization by 5 – 10%

• Negotiations underway to further optimize gathering and processing rates˃ Considering awarding new business opportunities – NGL fractionation,

processing, oil and water gathering, condensate exports, LPG exports, undedicated formations

Reduced penalty payments by ~$50 million in 2016

Increase EBITDA by working with partners to rebalance feesfor the long-term profitability of all companies


HEDGING POSITION (1)

19(1) For calendar year 2016 as of March 18, 2016.

Swaps $2.84 Swaps $46.51

55%67%

Natural Gas2016

Oil2016


CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER6.25% Senior Notes due 2017 #027393390 N/A6.50% Senior Notes due 2017 #165167BS5 CHK177.25% Senior Notes due 2018 #165167CC9 CHK18A3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK196.625% Senior Notes due 2020 #165167CF2 CHK20A6.875% Senior Notes due 2020 #165167BU0 CHK206.125% Senior Notes Due 2021 #165167CG0 CHK215.375% Senior Notes Due 2021 #165167CK21 CHK21A8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8

#U16450AT2N/AN/A

4.875% Senior Notes Due 2022 #165167CN5 CHK225.75% Senior Notes Due 2023 #165167CL9 CHK232.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK352.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/

#165167CA3CHK37/ CHK37A

2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK384.5% 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

HEADQUARTERS

6100 N. Western AvenueOklahoma City, OK 73118WEBSITE: www.chk.com

CORPORATE CONTACTS

BRAD SYLVESTER, CFAVice President – Investor Relations and Communications

DOMENIC J. DELL’OSSO, JR. Executive Vice President and Chief Financial Officer

Investor Relations department can be reached at [email protected]

http://www.chk.com/

mailto:[email protected]

Howard Weil 2016 final

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