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.
HOWARD WEIL CONFERENCE
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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)
(2)
Includes capitalized interest.
As of February 23, 2016.
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CHESAPEAKE’S FOCUS IN 2016
WHAT WE PLAN TO DO
(1)
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
Includes stock-based compensation.
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2016 CAPITAL ALLOCATION
• 2016 program provides attractive return
on incremental capital and optimizes
commitments
2016 Capital Budget
Decreasing capital budget by ~57%
~$3.6B
$0.4B Cap Int.
$0.2B Other
(1)
• Anticipated full access to revolver
$1.3 – $1.8B
$0.3B Cap Int.
$3.0B
D&C
$0.8 – 1.3B
D&C
D&C Breakout
2015
Funding short-cycle cash generating
projects to maximize EBITDA
2015
$0.2B Other (1)
2016E
2016E
Drilled Uncompleted (DUC) Inventory
Focusing spend on completions
to reduce inventory
480
Drilling
45%
Completion
55%
Drilling 30%
225 – 250
Completion
70%
2015
(1)
2016E
Includes other exploration and development costs and PP&E.
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ATTRACTIVE ROR FROM INVENTORY PROGRAM
Short cycle return on capital
2016 Inventory Program
Inventory (1)
Gross
Investment
Gross
EUR / well
ROR (2)
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%
Eagle Ford Shale
Inventory reduction program yields strongest return per dollar invested
~50% of development budget allocated toward inventory reduction
(1)
(2)
(3)
Inventory well defined as DUC or completed waiting to TIL.
Pricing assumptions: 2016: $36/$2.18, 2017: $41/$2.62, 2018: $44/$2.69, 2019: $46/$2.73, 2020+: $48/$2.82.
Firm transport modeled as sunk cost.
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VAST U.S. ONSHORE ASSET PORTFOLIO
SIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE
Powder River Basin
20 mboe/d net (1)
Spud: 0 / TIL: 5
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
Mid-Continent
2016 D&C Asset Funding
94 mboe/d net (1)
Spud: 40-50 / TIL: 35-45
Barnett Shale
STACK/
Mid-Con
22%
Haynesville
32%
70 mboe/d net(1)
Spud: 0 / TIL: 5
Haynesville Shale
Eagle Ford Shale
Eagle Ford
Shale
33%
102 mboe/d net (1)
Spud: 25-35 / TIL: 50-60
Marcellus
6%
(1)
97 mboe/d net
Spud: 20-30 / TIL: 170-180
Other
1%
~8.1mm net acres in developed & undeveloped leasehold
(1)
(2)
Average daily production 4Q’15.
Includes production volumes from legacy Devonian wells in West Virginia and Kentucky (~8 mboe/d net).
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Utica
6%
RECORD OF CONTINUOUS IMPROVEMENT
› Resilient production
despite substantial
reductions in capital
expenditures
Production
670
648
706
679
$6.7
2012
2013
2014
2015
Production (mboe/d)
Debt Principal $B
$13.1
$1.3 - $1.8
$13.2
2016 E
CapEx ($B)
(4)
Operating Costs
$7.76
$6.60
$9.7
$5.93
$5.17
$4.30 - $4.70
Continued
progress
in ‘16
(1)
(2)
(3)
(4)
2013
2014
(1)
(4)
$11.8
2012
(1)
$7.8
$14.7
$3.6
› Continued improvement
expected in 2016
605 - 635
2015
2016 E
Production range and total capital expenditure guidance from 2/24/16 outlook. Includes capitalized interest.
Production cost and net G&A guidance from 2/24/16 outlook.
Includes stock-based compensation.
Historical capital spend, debt principal, and operating costs contain Seventy Seven Energy data.
2012
2013
2014
Production cost ($/boe)
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2015
2016 E
Net G&A ($/boe)
8
(3) (4)
(2)
CONTINUOUS IMPROVEMENT IN CAPITAL EFFICIENCY
Continually improved
F&D cost across the
portfolio(1)
Mid-Continent
Eagle Ford Shale
37%
$22
$18
Significant
improvements
forecasted for 2016
2012
$21
$14
$14
2014
2015
$19
$18
2012
$7
$6
2014
2015
2013
2014
$17
2015
Marcellus Shale
56%
47%
$9
$8
68%
$13
2013
$15
Utica Shale
Haynesville Shale
2012
2013
34%
$26
2012
$10
$9
$8
2013
2014
2015
2012
2013
(1) Data represents average net D&C $ / net EUR in boe, grouped by TIL year.
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$6
$5
2014
2015
STACKED STRONG IN THE MID-CONTINENT
INDUSTRY LEADING MID-CONTINENT PRODUCER
• 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
Meritt 12-18-6 1G
15 days online
426 BOPD
972 MCFPD
Luber 28-18-7 1H
15 days online
440 BOPD
221 MCFPD
Rouce 4-17-10 1H
594 BOPD
876 MCFPD
Hughes Trust 33-18-7 1H
1,239 BOPD
486 MCFPD
Oswego
• Industry leading cost and drilling performance
Type
Curve
Top
Performer (2)
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%
$34/bo
$20/bo
Stangl 36-16-9 1H
1,161 BOPD
1,316 MCFPD
New well currently flowing back
IP is 30 day avg production
Meramec
Wittrock 16-16-9 1H
1,164 BOPD
3,144 MCFPD
PV10 Breakeven
Oil Price
(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.
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STRONG EARLY MERAMEC RESULTS
140,000
Chesapeake
Operated (1)
Cumulative Production, BOE
120,000
Competitor
Operated (2)
100,000
80,000
Expansive
unconventional
experience and strong
acreage position
delivering robust early
Meramec results
60,000
40,000
20,000
0
0
(1)
(2)
20
40
60
80
100
Days Producing
120
140
160
Represents three Chesapeake operated wells.
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.
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180
EAGLE FORD SHALE
ENHANCED ECONOMICS AND EFFICIENCIES
Drilling Cycle Time and Total Measured Depth
25
Projected 2016 well cost of $4.2mm
•
High-graded core position held with
20-30 new wells in 2016 delivering
a positive return
Drilling Days
20
17,000
16,500
17
15
15
13
16,000
12
11
15,500
10
15,000
5
•
Inventory TILs delivering 20% –
30% ROR (1)
•
14,500
0
14,000
2012
2013
2014
Cycle Time
Significant field-wide efficiency
gains driving ROR higher
2015
2016E
Avg. Total Measured Depth
Average Well Cost
$10
$8.1
$ in millions
$8
$6.9
$5.9
$6
$5.4
(2)
$4.2
$4
$2
$0
2012
(1)
(2)
2013
2014
2015
Pricing assumptions: 2016: $36/$2.18, 2017: $41/$2.62, 2018: $44/$2.69, 2019: $46/$2.73, 2020+: $48/$2.82.
Normalized to 6,500’ lateral length.
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2016E
Measured Depth (ft.)
•
HAYNESVILLE SHALE
CONTINUOUS IMPROVEMENT IN A MATURE ASSET
• Continued focus on field-wide extended
lateral development
• Optimized 2016
program capitalizes
on recent
improvements in
midstream contracts
Commitment
Remaining, 30%
Completion Enhancements Increasing Productivity
Cumulative Production (Mcf)
• Significant productivity uplift due to CHK
optimized completions
4,000
3,500
3,000
50%
2,500
2,000
1,500
Tighter cluster spacing, higher proppant
volumes and enhanced subsurface
targeting driving productivity higher
1,000
500
0
0
6
Commitment
Satisfied, 70%
Months
12
Legacy Field Completions
18
24
CHK Optimized Completions
Extended Lateral Efficiency Advantage
2016E: 8,000’
avg. LL
$2.26
10,000’
7,500’
$1.62
70% Complete
Will satisfy 70% of drilling commitment with
Williams by year-end
$1.32
$1.12
5,150’
4,500’
4,500' Traditional
5,150' Modern
7,500' Extended
Lateral
Well Cost/Lateral Ft ($1,000/ft)
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10,000' Extended
Lateral
Lateral Length (ft)
13
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.
2015
2Q
2016
3Q
4Q
1Q
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
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2Q
14
APPENDIX
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27% REDUCTION IN 2017 MATURING/PUTTABLE DEBT
PROACTIVE LIABILITY MANAGEMENT
Reduced 2017 maturing/puttable
debt obligations by $594 million
since 9/30/15
$2,500
$2,211
$2,000
$1,617 (1)
$1,168
$485mm
$1,500
$ MM
Total incremental liquidity since 9/30/2015
through proactive liability management (2)
$902
$1,000
Incremental
Liquidity
Financial Transaction
$660
$380
Debt Exchange
$305 million of new 2nd lien
$291 million
$382
$336
Open Market
Repurchases
$99 million of cash
$86 million
9/30/15 Outstanding
3/16/16 Outstanding
Equity for Debt
Exchanges
17.3 million shares (valued
at $73 million)
$108 million
$500
$0
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.
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MATURITY PROFILE
PROACTIVE LIABILITY MANAGEMENT
(1)
2015 Debt
Reduction
$861
Liabilities(2)
$594
$3,064
$674
$396
$824
$137
$1,617
$716
$878
$394
$1,104
$1,126
$876
$500
$384
(3)
$2
2015
(1)
(2)
(3)
2016
2017
2018
2019
2020
2021
2022
2023
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.
Recognizes earliest investor put option as maturity for the 2.50% 2037 and 2.25% 2038 Contingent Convertible Senior Notes.
Reflects amount that was not put to the company in 2015; next investor put date is 2020.
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IMPROVING AND REBALANCING MIDSTREAM
COMMITMENTS
Increase EBITDA by working with partners to rebalance fees
for the long-term profitability of all companies
• 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
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HEDGING POSITION (1)
Natural Gas
Oil
2016
2016
55%
67%
Swaps $2.84
Swaps $46.51
(1) For calendar year 2016 as of March 18, 2016.
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CORPORATE INFORMATION
HEADQUARTERS
PUBLICLY TRADED SECURITIES
6100 N. Western Avenue
Oklahoma City, OK 73118
WEBSITE: www.chk.com
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
BRAD SYLVESTER, CFA
Vice President – Investor Relations
and Communications
6.125% Senior Notes Due 2021
#165167CG0
CHK21
5.375% Senior Notes Due 2021
DOMENIC J. DELL’OSSO, JR.
Executive Vice President and
Chief Financial Officer
4.875% Senior Notes Due 2022
#165167CK21
#165167CQ8
#U16450AT2
#165167CN5
CHK21A
N/A
N/A
CHK22
5.75% Senior Notes Due 2023
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CHK23
2.75% Contingent Convertible Senior Notes due 2035
#165167BW6
CHK35
Investor Relations department
can be reached at ir@chk.com
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
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CHK PrD
CORPORATE CONTACTS
8.00% Senior Secured Second Lien Notes due 2022
5.0% Cumulative Convertible Preferred Stock (Series 2005B)
5.75% Cumulative Convertible Preferred Stock
5.75% Cumulative Convertible Preferred Stock (Series A)
Chesapeake Common Stock
CUSIP
HOWARD WEIL CONFERENCE
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TICKER
N/A
N/A
N/A
CHK