BARCLAYS CEO ENERGY-POWER CONFERENCE ... we are going 2016 –2020 CHK IS POSITIONED TO OUTPERFORM...

BARCLAYS CEO ENERGY-POWER CONFERENCESeptember 8, 2016

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, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, general

and administrative expenses, capital expenditures, the timing of anticipated noncore asset sales and proceeds to be received therefrom, projected cash flow and liquidity, our ability to

enhance our cash flow and financial flexibility, plans and objectives for future operations (including our ability to optimize base production and execute gas gathering agreements), the

ability of our employees, portfolio strength and operational leadership to create long-term value, 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; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital

markets on favorable terms or at all; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; a further

downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due low

commodity prices; 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 our ongoing 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; impacts of potential legislative and regulatory actions addressing climate change; federal and

state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; 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; terrorist activities and cyber-attacks adversely impacting our operations; potential

challenges of our spin-off of Seventy Seven Energy Inc. (SSE) in connection with SSE's recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code; an interruption

in operations at our headquarters due to a catastrophic event; the continuation of suspended dividend payments on our common stock and preferred stock; certain anti-takeover

provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or

other means.

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 presentation, and we undertake no obligation to update any of the information provided in this presentation, except as

required by applicable law.

PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate present value, discounted at 10% per annum, of estimated future cash flows of our estimated

proved reserves before income tax and asset retirement obligations. Management believes that PV-10 provides useful information to investors because it is widely used by

professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when

estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered as an

alternative to the standardized measure of discounted future net cash flows as computed under GAAP. With respect to pro forma changes in PV-10, it is not practical to calculate taxes

on a pro forma basis because GAAP does not provide for disclosure of standardized measure on such basis.

Barclays CEO Energy-Power Conference 2

OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES


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

Explore

> Leverage innovative technology

and expertise

> Explore and exploit new growth

opportunities

Business Development

> Optimize portfolio through strategic

divestitures

> Target strategic acquisitions

> Enhance and expand the portfolio

Financial Discipline

> Balance capital expenditures

with cash flow from operations

> Increase financial and operational

flexibility

> Achieve investment grade metrics

Strength and Depth of Portfolio

Operational Leadership

Differential Business Improvement

Where we are going2016 – 2020

CHK IS POSITIONED TO OUTPERFORM


Strengthened the balance sheet,

reduced complexity and legacy

commitments

Leverage portfolio strength and

depth to drive efficient growth

and further improve debt metrics (3)

2xNet debt/EBITDA

5%–15%Annual production growth

Where we have been2012 – 2016

(1) From 12/31/2012 through 6/30/2016

(2) Includes production expenses and general and administrative expenses, including stock-based compensation

(3) Assumes strip pricing through 2017 and $3/mcf and $60/bbl thereafter

~50% reductionIn total leverage (1)

= $10.6 billion

~50% reductionIn cash costs per boe (2)

= $4.10/boe in 2016E

Cash flow neutrality achievable in 2018Based on 2017 investment

$0

$5,000

$10,000

$15,000

$20,000

$25,000

2012 Q2-'16E(1)

REDUCED TOTAL LEVERAGE AND COMPLEXITY

Chesapeake continues to

simplify the business:

> Eliminated finance leases, subsidiary

preferred equity and seven VPPs

> Optimizing the capital structure


$m

m

$21,537

$10,894

2012 (1) 2Q’16 (1)

Credit Facility

Secured Loans & Notes

VPPs

Subsidiary Preferred Equity

Unsecured Notes

Operating & Finance Leases

Preferred Stock

(1) Assumes euro-denominated notes are converted to USD at the relevant 12/31 exchange rate for each calendar year;

for 2Q’16, exchange rate and credit facility balance are as of 6/30/16

~50% reductionIn total leverage

= $10.6 billion

($4,000)

($3,000)

($2,000)

($1,000)

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

Debt In

cre

ase/R

eduction (

$m

m)

PROACTIVE LIABILITY MANAGEMENT INDUSTRY-LEADING DEBT REDUCTION SINCE 1/1/2013

7Barclays CEO Energy-Power Conference

Source: Company filings as of 12/31/2012 and 6/30/2016. CHK data represents principal reduction of long-term debt,

while peer company data represents carrying value reduction of long-term debt, as principal balances are not always disclosed.

% Debt Increase/Reduction

34% reduction = $4.4 billion In debt principal reduction

CHK APA ECA HES MUR MRO EOG OXY DVN APC NBL COP

-34% -29% -26% -19% 9% 9% 11% 9% 9% 18% 93% 32%

REDUCTION IN 2017 MATURITIES


$382 $337 $297

$660

$315$233

$1,168

$730

$130

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

9/30/15 Outstanding 6/30/16 Outstanding Pro Forma

2.50% 2037 6.5% 2017 6.25% 2017

$2,210

$1,382 (2)

Financial Transaction Liquidity Savings (4)

Debt Exchange$305mm of

2nd lien notes$291mm

Open Market

Repurchases$99mm of cash $86mm

Equity for Debt

Exchanges

68.6mm shares

(valued at $295mm)$354mm

Tender Offer$722mm of 1.5 lien

Term Loan$695mm

~$1.4 billion

$3,091 (1)

Available

Liquidity

$660 (3)

Sources: Company management and disclosures. Note: $ in millions.

(1) $4.0 billion credit facility plus cash, less outstanding borrowings and letters of credit as of 6/30/2016

(2) 6.25% 2017’s converted to USD for entire period using exchange rate of $1.1106 to €1.00 as of 6/30/2016

(3) Assumes non-convertible tender participation as of early tender deadline in addition to full convertible tender participation up to sub-cap

(4) Incremental liquidity savings includes principal savings and net interest impact

37% reductionIn maturities from 9/30/15 to 6/30/16

70% reductionPro forma from current tender offer

BARNETT EXIT AND WILLIAMS RENEGOTIATIONSTRENGTHENING THE FOUNDATION OF THE BUSINESS

~$1.9 billion of midstream commitments

expected to be eliminated

• Chesapeake agreed to convey Barnett interests to

a private company

˃ Expected to eliminate current gathering agreement,

minimum volume commitments and fees pertaining

to Barnett assets

˃ Williams will receive ~$334mm from CHK and an

additional sum from the private company


$200 – $300mm increaseIn annual operating income from

2016 through 2019 (1)

Barnett

Expected 36% reduction in Mid-Continent

gathering costs

• Renegotiated Mid-Continent gathering agreement

in exchange for a payment of $66mm

Mid-Con

Together, these transactions

are expected to provide:

~$550mm uplift To total company PV10 (3)

~$715mm reduction In total GP&T expenses

in 2016 and 2017 (2)

(1) Before charges and other termination costs associated to this transaction

(2) Gathering, processing & transportation expenses, inclusive of projected MVC shortfall payments

(3) As of 12/31/2015

CAPITAL EFFICIENCY HOLDS PRODUCTION FLATDESPITE ASSET DIVESTITURES OF $16+ BILLION

• Spending 10% of 2012 capex program while producing equivalent volumes

• $16+ billion in divestitures led to 50% reduction in total leverage

• Relatively flat absolute production through growth of retained assets


Sources: Company management and disclosures

(1) Production range and total capital expenditure guidance from 8/9/2016 Outlook; includes capitalized interest

(2) Historical capital spend and operating costs contain Seventy Seven Energy data

648 670706

679611 – 638 (1)

$14.7

$7.8$6.7

$3.6

2012 2013 2014 2015 2016 E

$1.3 – $1.8 (1)

Production (mboe/d)Capex ($B) (2)

648 670706

679611 – 638 (1)

$14.7

$7.8$6.7

$3.6

2012 2013 2014 2015 2016 E

$1.3 – $1.8 (1)

(1) Includes production expenses and general and administrative expenses, including stock based compensation

(2) 2016E represents 8/9/2016 guidance midpoint

SIGNIFICANT REDUCTIONS IN CASH COSTS

Industry-leading cash cost structure:

> Relentless focus on cost management

> Operational leadership and technical

capabilities provide industry-leading

production expense


~50% reductionIn production and G&A expenses per boe since 2012

$2.28

$0.80

$5.52

$3.30

2012 2016E

Cash Costs ($/boe) (1)(2)

G&A LOE

$7.80

$4.10

HAYNESVILLE SHALEGAME-CHANGING SHIFT IN ECONOMICS


• Completions optimization and extended

laterals significantly increases ROR and

NPV in all areas

• CA 1H confirms the ability to flow at

higher sustained rates in Haynesville

utilizing larger stim design

CA 1H38 MMcfd & 7,450 psi;

25 psi/day drawdown

3,000 lbs/ft proppant

CA 2H23 MMcfd & 7,400 psi;


PCK 2H23 MMcfd & 7,640 psi;


PCK 1H31 MMcfd & 7,680 psi;


CHK Operated Rigs

CHK Leasehold

10,000' Wells

Completion Tests

Nabors 2H & 3HDrilled X-Unit laterals;

Q3 3,000 and 5,000 lbs/ft

completion test

Bossier ParishQ4 10,000' lateral;

5,000 lbs/ft completion test

PKY 1HQ3 10,000' lateral;

4,000 lbs/ft completion test

(1) Economics run at $3/mcf flat

3%

18%

25%

37%

47%

5,000'Springridge

Lateral

7,500'Springridge

Lateral

10k SpringridgeLateral

10k CA 12&13-15-15 2H

10k CA 12&13-15-15 1H

Longer Laterals

Reduced

D&C Costs

Enhanced

Completion

& High IP

2014 20162015

Rate of Return (1)

EAGLE FORD SHALEEXTENDED LATERALS KEY TO REDUCING DEVELOPMENT COST

(1) Based on spud date

(2) Average cost per foot of wells drilled and/or completed within the time period


• Strategic shift to longer laterals

has reduced development cost per

foot by 60%

• ~65% of cost reductions are

attributable to sustainable

operational efficiency gains

5,600'6,500'

9,000' 9,300'10,500'

5,300'

'14 YE '15 Avg. 1Q'16 2Q'16 YE Goal Karnes AreaCompetitor

Lateral Length (1)

$1,000$923

$488 $430 $405

$962

2014 YE 2015 Avg. 2016 1QE 2016 2QE YE Goal Karnes AreaCompetitor

Total Well Cost per Lateral Foot (2)

YE Goal'14 YE '15 Avg. 1Q'16 2Q'16

~25%At 5,300'

~65%At 10,500'

Rate of Return for

2016 Development Program

$5.3 $4.9

$2.6 $2.3 $2.1

$5.1

'14 YE '15 Avg. 1Q'16 2Q'16 YE Goal Karnes AreaCompetitor

Total Well Cost, Normalized to 5,300' LL ($mm)

'14 YE

UNRECOGNIZED VALUE, UNLOCKED POTENTIALSTRENGTH AND DEPTH OF PORTFOLIO

16Barclays CEO Energy-Power Conference

(1) Economics run at $3/mcf and $60/bbl oil flat

(2) Operated gross, risked locations

(3) Includes Upper Eagle Ford and Austin Chalk locations

Tremendous resource optionality provides Chesapeake

with a competitive advantage for years to come

1,110

2,400

600

1,900

200

650

2,400

275

50

350

1,350 425

1,750

550

2,250

350

275

500

Eagle Ford Mid-Continent Marcellus Powder River Haynesville Utica Exploration andTechnology

Opportunities

10,500+ locations>20% ROR (1)(2)

(3)

5,600+ locations>40% ROR (1)(2)

5,260

3,2252,900

2,600

1,8251,575

2,500+

>40% ROR 20% – 40% ROR <20% ROR

• CHK has the opportunity to develop

the field with current technology

> Longer laterals

> Optimized completions

> Significantly enhanced returns

• Opportunity for exceptional value realization

from captured resources for years to come

HAYNESVILLE SHALETHE CHESAPEAKE ADVANTAGE


Chesapeake has this opportunity

across all of its assets

Heavily

developed

competitor

position

Substantial

development

opportunities

remain for CHK

CHK Haynesville Locations

Drilled;

25%

Remaining

Development;

75%

EAGLE FORD MULTIZONE RESOURCE POTENTIALAREAS OF INTEREST AND COMPETITOR ACTIVITY


Austin

Chalk

Lower

Eagle

Ford

Upper

Eagle

Ford

Staggered Wellbores

Competitor offset information was derived from public data

CHK South Texas Locations

Drilled;

25%

Remaining

Development;

75%

UTICA SHALEDRY GAS 2016 PROGRAM

• 2016 dry gas drilling program

˃ ~11,500' average lateral length

˃ ~$6.8mm D&C per well

˃ Average CHK WI of 99%


• Substantial growth planned for 2017

• Favorable gas differentials

> ~93% of dry gas is sent to Gulf markets

~45% ROR2016 drilling program

>350% Production growth

July 2016 – July 2017

Utica Dry Gas ProductionCHK Utica Dry Locations

Drilled;

10%

Remaining

Development;

90%

2020

Strategic targets


Substantial progress on every front

Reduced total leverage by

~50% ($10.6 billion)

Improved cash costs by

~50% per boe

Reduced financial and balance

sheet complexity

High-graded portfolio –

10,500+ locations above 20% ROR ANALYST DAY

October 20, 2016 Oklahoma City

Grow production 5% – 15%

annually

Retire $2 – $3 billion of debt

through asset divestitures

Achieve 2x net debt/EBITDA

2016

$8.43

$8.55 $8.58

$7.60 – $8.10

2014 2015 2016E 2016E New 2017E New

GP&T $/boe (incl. MVC shortfall) (1)

$7.15 – $7.65

GATHERING, PROCESSING & TRANSPORTSUBSTANTIAL COST STRUCTURE IMPROVEMENT GOING FORWARD

Barclays CEO Energy-Power Conference

(1) Includes all actual and projected MVC payments; 2016E represents guidance midpoint.

22

2017 GP&T expenses expected to improve by ~14% after

midstream transactions

2016 GP&T expense

reduced by ~9%

HEDGING POSITION


(1) For July – December 2016 production as of August 4, 2016.

(2) Using midpoints for projected 2017 total production guidance as of August 9, 2016.

Oil2017 (2)

23%

Swaps $47.49/bbl

Natural Gas2017 (2)

33%

30%Swaps

3%Collars

$3.00 / $3.48/mcfNYMEX

$3.02/mcfNYMEX

Natural Gas2016

74%

71%Swaps

3%Collars

$3.00 / $3.48/mcfNYMEX

$2.76/mcfNYMEX

Oil2016

71%

Swaps $46.60/bbl

NGL2016

32%

Ethane Swaps $0.17/galPropane Swaps $0.46/gal

CORPORATE INFORMATION

PUBLICLY TRADED SECURITIES CUSIP TICKER

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

8.00% Senior Secured Second Lien Notes due 2022#165167CQ8

#U16450AT2

N/A

N/A

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/

#165167826N/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 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 at [email protected]


http://www.chk.com/

mailto:[email protected]

BARCLAYS CEO ENERGY-POWER CONFERENCE ... we are going 2016 –2020 CHK IS POSITIONED TO OUTPERFORM...

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Transcript of BARCLAYS CEO ENERGY-POWER CONFERENCE ... we are going 2016 –2020 CHK IS POSITIONED TO OUTPERFORM...