CITI 2016 GLOBAL ENERGY AND
UTILITIES CONFERENCE
May 10, 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; 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 the event of a bankruptcy of SSE; 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 this presentation, and we undertake no
obligation to update any of the information provided in this presentation, except as required by applicable law.
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2016 KEY ACHIEVEMENTS TO DATE
• ~$1.2 billion in asset divestitures closed or under signed PSA
> Up from $700mm announced in February
> Reiterating target of $1.2 – $1.7 billion in asset divestitures in 2016
• Amended revolving credit facility covenants and reaffirmed
$4 billion borrowing base capacity
• Reduced 2017 maturing / puttable debt by ~$600 million a 27%
reduction since 9/30/15; $282mm YTD
• Cash costs down 28% in first quarter YOY
(1)
(1) Includes production expenses and general and administrative expenses, including stock based compensation.
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CHESAPEAKE’S FOCUS IN 2016
WHAT WE PLAN TO DO
2016 Plan
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
2016 Progress to Date
■
■
■
■
■
■
■
On track to reduce capital budget by >50% YOY
Reduced cash costs by 28% first quarter YOY (1)
$1.2 billion in total asset divestitures closed or
under PSA YTD
Reiterating target of $1.2 – $1.7 billion in asset
divestitures in 2016
Continued progress on contract renegotiations
>50% of D&C capital allocated for inventory
drawdown
Reduced 2017 maturing/puttable debt by
~$600mm, a 27% reduction since 9/30/15; $282mm
YTD as of 3/31/16
(1) Includes production expenses and general and administrative expenses, including stock based compensation.
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SIGNIFICANT PROGRESS ON ASSET DIVESTITURE GOAL
~$1.2 billion
Expected gross proceeds from
2016 signed or closed divestitures (1)
$45 million
Minimal 2016 projected
EBITDA impact
(1)
(2)
~35 mboe/d
Minimal impact to 2016 production
volumes (60% gas) (2)
$1.2 - $1.7 billion
Targeted asset divestitures by YE 2016
Approximately $950 million in net proceeds after VPP obligations are met.
Production from signed or closed divestitures is approximately 60% gas, 20% oil, and 20% NGL.
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MERAMEC VALUE ACCELERATION
• Partial Meramec monetization for
$470mm accelerates significant value
for shareholders
• Maintaining a substantial position after
2016 divestitures
˃ 52,000 acres remain in STACK corridor
˃ 1.5mm acres remain in the Mid-Continent
• ~$100mm in capital available to redirect
to other investment opportunities
• Borrowing base not impacted by
Meramec monetization
Budgeted 2016 STACK D&C CAPEX
$40
$20
$20
3Q'16E
4Q'16E
$20
1Q'16
2Q'16E
Effective Date: 4/1/16
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CAPITAL DISCIPLINE REMAINS FOCUS
• On track for >50% reduction in total capex vs. 2015
˃ Capex down 75% in first quarter YOY
• Majority of 2016 projected capex focused on DUC inventory drawdown
Production (2)
$1,600
800
$1,200
600
Produciton (mboe/d)
Quarterly CapEx Spend ($mm)
Capital Spending (1)
$800
$400
$0
200
0
1Q
2Q
2015
(1)
(2)
400
3Q
2016E
4Q
1Q
2Q
3Q
2015
2016E
Includes D&C costs, leasehold, G&G, other PP&E and capitalized interest.
Unadjusted for asset sales.
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4Q
CONTINUOUS IMPROVEMENT OF CASH COSTS
• Plan to reduce G&A by 15%
and LOE by 10% in 2016
Quarterly Cash Costs ($/boe) (1)
$5.75
$5.40
$4.87
$4.64
$4.14
• Progress being made on both fronts
in early 2016
> 28% reduction in cash costs
in first quarter YOY (1)
> ~$100mm reduction in cash
costs YOY (1)
1Q'15
$7.76
2Q'15
3Q'15
4Q'15
1Q'16
Annual Cash Costs ($/boe) (1)
$6.60
$5.93
$5.17
• History of continuous cash cost
improvement
2012
2013
2014
2015
(1) Includes production expenses and general and administrative expenses, including stock based compensation.
(2) Guidance as of May 5, 2016.
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$4.10 – $4.50 (2)
2016 E
VAST U.S. ONSHORE ASSET PORTFOLIO
SIGNIFICANT VALUE IN DEVELOPED AND UNDEVELOPED ACREAGE
Powder River Basin
17 mboe/d net (1)
Spud: 0 / TIL: 5
Marcellus Shale
Utica Shale (2)
144 mboe/d net (1)
Spud: 0-5 / TIL: 20
146 mboe/d net (1)
Spud: 0-5 / TIL: 45-55
Mid-Continent
93 mboe/d net (1)
Spud: 30-40 / TIL: 25-35
Barnett Shale
69 mboe/d net (1)
Spud: 0 / TIL: 5
Haynesville Shale
Eagle Ford Shale
112 mboe/d net (1)
Spud: 25-35 / TIL: 50-60
91 mboe/d net (1)
Spud: 20-30 / TIL: 170-180
(1)
(2)
(3)
~8.0mm net acres
in developed and
undeveloped
leasehold (3)
Average daily production 1Q’16.
Includes production volumes from legacy Devonian wells in West Virginia and Kentucky.
Estimated as of 3/31/2016.
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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
2013
2012
$6
2014
2015
2012
2014
$9
56%
68%
$7
2013
$17
2015
Marcellus Shale
$18
$13
$15
Utica Shale
Haynesville Shale
2012
2013
34%
$26
$10
$9
$8
2013
2014
2015
47%
$8
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
HAYNESVILLE SHALE
LONGER LATERALS DRIVING EFFICIENCY
Longer Lateral Productivity (1)
• 23% decrease in projected
D&C costs in 2016 vs. 2015
• Long laterals provide 63%
increase in 160-day
cumulative gas production
3,500
3,000
2,500
2,000
1,500
500
0
100
200
300
400
Time (Days)
Efficiency gains driving ROR higher
• ~8,000’ average lateral length
in 2016
63%
Increase
1,000
0
Legacy Wells: ~4,400' LL
10,000' LL Wells
Lateral Length Progression
9,000
Drilled Lateral Length (ft.)
˃
Cumulative Gas (MMcf)
4,000
8,000
7,000
75%
Longer laterals
projected to be drilled
in 2016E vs. 2013
6,000
5,000
4,000
2013
2014
2015
(1) Legacy wells includes 27 wells with in-unit laterals. 10,000 LL includes three wells traversing two sections with down time removed.
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2016E
EAGLE FORD SHALE
• Per foot development costs
reduced by ~50%
• Current returns on development
program at $45/bbl oil
outcompete 2014 program at
$80/bbl oil (1)
Lateral Length
12,000
9,000
10,000
8,000
6,500
5,600
4,000
2014 YE
2015 Avg.
2016 1QE
2016 2QE
YE Goal
$1,500
$1,000
$923
$1,000
Cumulative Oil (Mbo)
development program (1)
6,500
6,000
$600
$522
$429
$500
$0
2014 YE
25
50%
Expected ROR for 2016
10,500
Cost per Foot
Dollars per Foot
• Outstanding well performance to
date for extended lateral program
Lateral Length (ft.)
CAPITAL EFFICIENCY DRIVING COMPETITIVE RETURNS
50
2015 Avg.
2016 1QE
2016 2QE
YE Goal
Cumulative Oil Production
40
30
20
XL Pad - Avg. LL 9,900'
10
Control Avg. LL 4,983'
0
0
10
20
30
40
50
60
Days
(1) Pricing assumptions: 2016: $47.32/$2.52, 2017: $49.00/$3.01, 2018: $50.22/$3.04, 2019: $51.35/$3.04, 2020+: $53/$3.25
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70
80
90
100
THE TRANSFORMATION CONTINUES
Maximize Liquidity: 2016 capital spend is down more than ~50%
Optimize Portfolio: $1.2 billion in asset divestitures signed YTD
Increase EBITDA: Reduce costs and work to restructure contracts
Debt Management/Elimination: ~$600 million reduction in 2017 debt (1)
2016
2015
4Q
Second lien debt
exchange
1Q
Announced
$700mm in
noncore asset
divestitures
2Q
Announced
$500mm in asset
divestitures;
Amended credit
facility
3Q
4Q
Continue maximizing liquidity,
increasing EBITDA and
reducing debt
(1) Since 9/30/2015
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APPENDIX
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REVOLVER CREDIT FACILITY AMENDMENT
• Revolving credit facility capacity affirmed at $4 billion
• Facility will not be subject to another redetermination until June 2017
• Senior secured leverage ratio suspended through September 2017
˃ Resuming at 3.5x thereafter through December 2017 and decreasing to 3.0x
thereafter
• Interest coverage ratio covenant was reduced to 0.65x from 1.1x
through March 2017
> After which it will increase to 0.70x through June 2017, then reverting to 1.2x in
September 2017 and to 1.25x thereafter
Amendments to revolver provides significant liquidity
and optionality in 2016 for Chesapeake
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27% REDUCTION IN 2017 MATURING/PUTTABLE DEBT
$2,500
From 9/30/2015 through 3/31/2016, reduced
2017 maturing/puttable debt obligations by
$2,220
~$600mm
$2,000
$1,625 (1)
$1,168
$1,500
~$500mm
$ MM
Total incremental liquidity since 9/30/2015
through proactive liability management (2)
$902
$1,000
Financial Transaction
$660
Debt Exchange
$313mm of new
2nd lien
$291mm
Open Market
Repurchases
$99mm of cash
$86mm
Equity for Debt
Exchanges
17.3mm shares
(valued at $73mm)
$108mm
$380
$500
$382
$344
$0
9/30/15 Outstanding
6.25% 2017
Liquidity Savings
3/31/16 Outstanding
6.5% 2017
2.5% 2037
(1) 6.25% 2017's converted to USD for entire period using exchange rate of $1.138 to €1.00 as of 3/31/16.
(2) Incremental liquidity savings includes principal savings and net interest impact.
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CREDIT COLLATERAL SUPPORT
$1,097
$400
Midstream collateral requirements decreasing
while hedging counterparty requirements
increased due to higher commodity prices
$1,000
$350
$826
Millions USD (1)
$733
$730
$800
$250
$32
$600
$32
$200
$104
$57
$150
$400
$100
$11
$200
$133
$34
$111
$50
$4
$0
$11
$5
12/31/2015
Posted - Midstream
$47
$0
2/24/2016
Posted - Hedging
3/31/2016
Posted - Others
5/3/2016
Potential – Midstream and Insurance
(1) Excluding the supersedeas bond with respect to the 6.775% Senior Notes due 2019 litigation.
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Millions USD
$300
HEDGING POSITION
NaturalGas
Gas(1)
Natural
2016
2016
(1)
Oil
NGL
2016
2016
38%
64%
Swaps $2.71/mcf
69%
Swaps $46.32/bbl
Ethane Swaps $0.17/gal
Propane Swaps $0.46/gal
73 bcf of 2017 gas volumes hedged with swaps @ $2.92
2.9 mmbbl of 2017 oil volumes hedged with swaps @ $42.53
(1) For April - December 2016 production as of May 3, 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
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CHK38
4.5% Cumulative Convertible Preferred Stock
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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
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TICKER
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CHK