howard weil conference weil 2016 final.pdf · 2016. 3. 22. · howard weil conference ~50% of...

HOWARD WEIL CONFERENCE March 22, 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, 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.

2 HOWARD WEIL CONFERENCE

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)

3

(1) Includes capitalized interest.

(2) As of February 23, 2016.

HOWARD WEIL CONFERENCE

CHESAPEAKE’S FOCUS IN 2016 WHAT WE PLAN TO DO

4

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

5

D&C Breakout Funding 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 Budget Decreasing capital budget by ~57%

2015 2016E

$3.0B

D&C

~$3.6B

$1.3 – $1.8B

(1)

(1)

$0.8 – 1.3B

D&C

$0.2B Other

$0.3B Cap Int.

$0.4B Cap Int.

$0.2B Other

Drilling 30%

Completion 70%


ATTRACTIVE ROR FROM INVENTORY PROGRAM

6

Inventory (1) Gross

Investment Gross

EUR / 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.

Marcellus Shale 130 mboe/d net (1)

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

148 mboe/d net (1)

Spud: 0-5 / TIL: 45-55

Barnett Shale 70 mboe/d net(1)

Spud: 0 / TIL: 5

Eagle Ford Shale 97 mboe/d net (1)

Spud: 20-30 / TIL: 170-180

Powder River Basin 20 mboe/d net (1)

Spud: 0 / TIL: 5

Mid-Continent 94 mboe/d net (1)

Spud: 40-50 / TIL: 35-45

Haynesville Shale 102 mboe/d net (1)

Spud: 25-35 / TIL: 50-60

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

7

2016 D&C Asset Funding

Haynesville 32%

Marcellus 6%

Utica 6%

Other 1%

Eagle Ford Shale 33%

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

8

(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.

$7.76

$6.60 $5.93

$5.17

2012 2013 2014 2015 2016 E

Operating Costs

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

648 670 706 679 605 - 635

$14.7 $7.8

$6.7

$3.6

2012 2013 2014 2015 2016 E

Production (mboe/d) CapEx ($B)

Production

(3)

$13.1 $13.2

$11.8

$9.7

2012 2013 2014 2015 2016 E

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

9

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

$19

$13

$7 $6

2012 2013 2014 2015

Haynesville Shale

68%

$22

$18

$14 $14

2012 2013 2014 2015

Mid-Continent

37% $26

$21

$15 $17

2012 2013 2014 2015

Eagle Ford Shale

34%

$9

$8

$6 $5

2012 2013 2014 2015

Marcellus Shale

47% $18

$10 $9 $8

2012 2013 2014 2015

Utica Shale

56%


Continually improved

F&D cost across the

portfolio(1)

Significant

improvements

forecasted for 2016

STACKED STRONG IN THE MID-CONTINENT INDUSTRY 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.

Mera

mec

O

sw

eg

o Undiscounted

Payout 2.1 yr 0.8 yrs

Rate of Return 39% >230%

PV10 Breakeven

Oil Price $31/bo $22/bo

Undiscounted

Payout 3.4 yrs 1.2 yrs

Rate of Return 23% >100%

PV10 Breakeven

Oil Price $34/bo $20/bo

Type

Curve

Top

Performer (2)


Wittrock 16-16-9 1H

1,164 BOPD

3,144 MCFPD

Rouce 4-17-10 1H

594 BOPD

876 MCFPD

New well currently flowing back

IP is 30 day avg production

Stangl 36-16-9 1H

1,161 BOPD

1,316 MCFPD

Luber 28-18-7 1H

15 days online

440 BOPD

221 MCFPD Hughes Trust 33-18-7 1H

1,239 BOPD

486 MCFPD

Meritt 12-18-6 1G

15 days online

426 BOPD

972 MCFPD

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0 20 40 60 80 100 120 140 160 180

Cu

mu

lative

Pro

du

ction

, B

OE

Days Producing

Expansive

unconventional

experience and strong

acreage position

delivering robust early

Meramec results

STRONG EARLY MERAMEC RESULTS

11

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 SHALE ENHANCED 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

17

15 13 12

11

14,000

14,500

15,000

15,500

16,000

16,500

17,000

0

5

10

15

20

25

2012 2013 2014 2015 2016E

Cycle Time Avg. Total Measured Depth

12

$ in

mill

ion

s

Dri

llin

g D

ays

Me

asu

red

De

pth

(ft

.)


$8.1

$6.9

$5.9 $5.4

$4.2

$0

$2

$4

$6

$8

$10

2012 2013 2014 2015 2016E

(2)

• Significant productivity uplift due to CHK

optimized completions

• Continued focus on field-wide extended

lateral development

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

0 6 12 18 24

Cu

mu

lati

ve P

rod

uct

ion

(M

cf)

Legacy Field Completions CHK Optimized Completions

$2.26

$1.62

$1.32 $1.12

4,500’ 5,150’

7,500’ 10,000’

4,500' Traditional 5,150' Modern 7,500' ExtendedLateral

10,000' ExtendedLateral

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

HAYNESVILLE SHALE CONTINUOUS IMPROVEMENT IN A MATURE ASSET

13

Completion Enhancements Increasing Productivity

Months

50%

2016E: 8,000’ avg. LL

70% Complete Will 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 2016

2Q 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 debt

by ~$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.


APPENDIX


$382 $336

$660

$380

$1,168

$902

$0

$500

$1,000

$1,500

$2,000

$2,500

9/30/15 Outstanding 3/16/16 Outstanding

$ M

M

6.25% 2017 6.5% 2017 2.5% 2037

(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 DEBT PROACTIVE LIABILITY MANAGEMENT

HOWARD WEIL CONFERENCE 16

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

$2

$1,617

$878 $1,104 $1,126

$876

$3,064

$384 $394 $500

$594

$137

$396

$674

$824

$861

$716

2015 2016 2017 2018 2019 2020 2021 2022 2023

(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 PROFILE PROACTIVE LIABILITY MANAGEMENT (1)

2015 Debt

Reduction

Liabilities(2)

(3)

HOWARD WEIL CONFERENCE 17

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

18

Reduced penalty payments by ~$50 million in 2016

Increase EBITDA by working with partners to rebalance fees

for 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 Gas 2016

Oil 2016

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/

#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 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]

mailto:[email protected]

howard weil conference weil 2016 final.pdf · 2016. 3. 22. · howard weil conference ~50% of...

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