barclays ceo energy-power conference ... we are going 2016 –2020 chk is positioned to outperform...
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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.
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OUR STRATEGYRELEVANT THROUGH COMMODITY PRICE CYCLES
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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
Where we are going2016 – 2020
CHK IS POSITIONED TO OUTPERFORM
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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
$25,000
2012 Q2-'16E(1)
REDUCED TOTAL LEVERAGE AND COMPLEXITY
Chesapeake continues to
simplify the business:
> Eliminated finance leases, subsidiary
preferred equity and seven VPPs
> Optimizing the capital structure
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$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
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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
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$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
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$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
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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
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~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
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• 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;
1,600 lbs/ft proppant
PCK 2H23 MMcfd & 7,640 psi;
1,600 lbs/ft proppant
PCK 1H31 MMcfd & 7,680 psi;
2,700 lbs/ft proppant
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
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• 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
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(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
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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
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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%
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• 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
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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
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(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
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(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]
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