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CITIBANK ENERGY INVESTOR TOUR
December 16, 2015
FORWARD-LOOKING STATEMENTS
2CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
• 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, and use leading-edge technology to drive capital efficiency, the timing of anticipated noncore 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 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; the limitations our level of indebtedness may have on our financial flexibility; 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.
• 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.
3Q’15 FINANCIAL AND OPERATIONAL RESULTS
(1) Includes stock-based compensation
(2) Adjusted for asset sales
(3) Oil and NGLs collectively referred to as “liquids”
Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 18 – 19
3CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
ADJ. EBITDA
$560mm
LIQUIDS MIX(3)
28% of total production3% YOY(2)
ADJ. EARNINGS/FDS
($0.05)
ADJ. PRODUCTION
667 mboe/d
PROD. and G&A EXP.
ADJ. OIL PRODUCTION
4% YOY(2)
114 mbo/d
9% YOY
$4.88/boe(1)
BUSINESS DELIVERY
4CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
Operational Leadership
Portfolio Strength & Flexibility
Financial Stability
Chesapeake continues to execute on its strategy
NEAR-TERM STRATEGY
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 5
Preserve
cash flow
generation
capability
• Enhance field
development
• Leading-edge
technology to
drive capital
efficiency
Use operating
and capital
flexibility as
a strength
• Optimize base
production
• Focus on core
positions
Improve
margins
• Restructure
midstream
contracts
• Reduce field
operating
expenses
• Reduce G&A
expenses
Maximize
liquidity
• Amended credit
facility
• Divest noncore
assets
FINANCIAL STABILITYMAXIMIZING LIQUIDITY
• Proactively working to increase liquidity
˃ Amended credit facility agreement maturing in 2019
˃ Noncore divestitures expected to total $200 – $300mm by 1Q’16
• Maintaining capital discipline during challenging commodity environment
• On target to beat February production guidance for FY 2015 despite:
˃ $500mm capital spending reduction
˃ Average voluntary curtailment of ~35,000 boe/d YTD
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 6
Portfolio strength and flexibility provides financial stability;
spending less and producing more
• Financial security and flexibility
> Borrowing base confirmed at
$4.0 billion
> Facility maturing in 2019
> Covenants restructured in light of low
commodity prices
> $2.4 billion of additional secured debt
available, should conditions warrant
FINANCIAL STABILITYCREDIT FACILITY AMENDMENT
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 7
$5.7 billionIn cash and undrawn credit facility
on 9/30/15
• Operational flexibility
> Reduced commitments and
continually improving capital
efficiency positions Chesapeake to
run a reduced capital program in
2016 to support liquidity focus
> Depth of portfolio allows for
continued, methodical sales of
noncore assets to enhance value
OPERATIONAL LEADERSHIP
8CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
• Enhanced base production of
existing assets
˃ Generated an additional 7 mmboe
net YTD
˃ Focused programs on
compression and artificial lift
˃ Reduced downtime through
enhanced winterization activities
~7 mmboeAdditional net base production
YTD vs. 2015 budget forecast
(1) Lateral lengths reported are drilled footage, not completed footage
9,395 9,36610,020
12,976 13,192
4,464
6,186
4,998
7,371
5,955
Miss Lime PRB Haynesville Utica Eagle Ford
2015 Record LL (ft.)
Avg. 2014 LL (ft.)
• Development teams extending
technological limits with operations
program
˃ Drilled the longest laterals(1) in each
of our major operating areas in 2015;
significantly enhancing economics
˃ Long laterals improve capital efficiency
($/boe) by 20 – 25% companywide
SUBSTANTIAL GROWTH OPPORTUNITIESMID-CONTINENT: MERAMEC AND OSWEGO
• Meramec
˃ First well 27 days spud to RR
˃ Second well 18 days spud to RR
• Oswego
˃ Three Oswego wells drilled to date
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 9
(1) Assumes NYMEX natural gas price of $3.00/mcf held constant
(2) Assumes $7.1mm well cost
(3) Assumes $3.2mm well cost
Production Mix Production Mix
Meramec$36 PV-10 Break-Even(1)(2)
Oswego$37 PV-10 Break-Even(1)(3)
NGL
Oil
Gas
~1,200 locationsMeramec and Oswego Limestone
CHK
Industry
CHK Hughes Trust 1H
Oswego Test
2052 BOEPD Peak
(93% Oil)
CHK Rouce 4-17-10 1H
Initial CHK 9,350’
Meramec well
CHK Wittrock 16-16-9 1H
9,220’ Meramec well
CHK Stangl 36-16-9 1H
10,000’ Meramec well
1723 BOEPD IP
(85% Oil)
1374 BOEPD IP
(80% Oil)
1309 BOEPD IP
(79% Oil)
Mississippian/Meramec
Oswego
All Rights
Shallow Rights
Second Meramec well exceeds play
performance at a stabilized rate of
1,900 boe/d with greater than 2,000 psi
(1) Assumes NYMEX natural gas price of $3.00/mcf.
SUBSTANTIAL VALUE UNDER HBP ACREAGEUPPER MARCELLUS
• Recent successful appraisal of the
Upper Marcellus unlocks more
than 1,000 economic locations(1)
˃ Well 1 peak rate 19 mmcf/d
˃ Well 2 peak rate 17 mmcf/d
˃ Future test wells in Susquehanna
and Wyoming counties
• Favorable development flexibility
as position is held by production
• No communication between Upper
and Lower Marcellus confirmed
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 10
>1,000 locationsBreak-Even (PV-10)(1) Upper Marcellus
Test Well 119 mmcf/d
Test Well 217 mmcf/d
OPTIMIZING VALUE FROM BASE PRODUCTIONUTICA SHALE
• Operating more efficiently
˃ Compressor/Artificial lift
optimization
˃ Pressure maintenance
program
˃ Choke management
˃ Better winter ops preparation
• Midstream improvements
˃ Line pressure decrease
˃ Fewer disruptions
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 11
12% increase2015 1H production driven by
base optimization
0
20
40
60
80
100
120
140
160
180
Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15
Avg
Daily
Ra
te (
mb
oe
/d)
2015 Gross Operated Base Production
Incremental Production
Avg Mboe/d
Previous Trend
Current Trend
mboe/d
DEVELOPMENT OPTIMIZATIONEAGLE FORD
• Leveraging Chesapeake’s
technical advantage
˃ First wells with laterals greater
than 12,500’ on flowback
˃ 13,000’ wells provide capital
reduction of more than 20% when
compared to two 6,500’ laterals
˃ Extended laterals improve
Eagle Ford capital efficiency
($/boe) by ~20%
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 12
Days Days
(1) Lateral lengths reported are drilled footage, not completed footage
Rogers E-1H;
12,611’ LL(1)
Faith-San Pedro F-4H;
13,192’ LL(1)
Current Rigs
CHK Leasehold
County
MATURITY WINDOW
Oil Window
Dry Gas Window
Wet Gas Window
Transition Window
0
600
1200
1800
0 5 10 15 20 25 30 35 40 45
Bopd
Oil Production RateRogers ExtendedLateral
Control 6400'
0
600
1200
1800
0 5 10 15 20 25 30 35 40
Bopd
Oil Production RateFaith ExtendedLateral
Control 6500'
TURNING EFFICIENCY INTO VALUEHAYNESVILLE
• Extended laterals
˃ Two 7,500’ lateral tests flowing an average of
16.1 mmcf/d for more than 170 days
˃ Production test of first three 10,000’ laterals in
4Q’15
˃ Technological innovation and continued cost
improvement are driving value into the
Haynesville
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 13
0
5
10
15
20
25
0 50 100 150
Avg
Daily
Gas R
ate
(m
mcf/
d)
Days
Haynesville Shale –Extended Lateral Performance
Nguyen 7500 Rate (mcfpd)
Nguyen 7500 Avg FTP (psi)
Unit Rate (mcfpd)
Unit FTP (psi)
10 mmcf/d higher
$289 $275 $246 $241 $234
$209
13
18 18 19
15
18
0
5
10
15
20
25
30
$0
$50
$100
$150
$200
$250
$300
Q2 Q3 Q4 Q1 Q2 Q3
2014 2014 2014 2015 2015 2015
Wells
Sp
ud
$/F
oo
t
Avg(CPF) Well Count
Drilling Cost Per Foot
Producing 7,500’ Nguyen wells
10,000’ lateral in progress
7,500 – 8,500’ laterals in progress
CHK Operated Rigs
CHK Leasehold
Multilateral Wells
Multisection
Extended Laterals
APPLYING NEW TECHNOLOGIESMID-CONTINENT
• Multilateral wells
˃ First multilateral expected to TIL
mid-December
˃ Potential to spread technology to other
plays – significant cost saving potential
• Multisection extended laterals
˃ Drilled two extended multisection laterals
˃ Saves ~$1.4mm as compared to two
standard laterals
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 14
27% decreasein D&C costs compared to drilling
two standard laterals
Multilateral
Wilber 26-27-11 1H
TD 10/8/2015
Extended Laterals
JJJ 23-25-11 1H
Est TIL 11/20/2015
Sunny 23-25-11 1H
TIL in Q4 2015
Extend and Multilateral Wells
Mississippi Lime
County
CHK Section Summary
Initial Miss Lime Multilateral well exceeds
1,200 boe/d
PORTFOLIO STRENGTH AND FLEXIBILITY
(2) Assumes NYMEX natural gas price of $3.00/mcf held constant(1) Assumes NYMEX oil price of $50/bbl held constant
15CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
PRB SUSSEX MISS LIME EAGLE FORD MID-CONSTACK
Oil Break-Even (PV-10)
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
HAYNESVILLE UTICA DRY UTICA WET MARCELLUS
Natural Gas Break-Even (PV-10) (2)(1)
Chesapeake’s diverse portfolio of highly efficient investments
is built to withstand the current commodity price environment
CHESAPEAKE’S STRATEGIC SCORECARD
16CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
Chesapeake is executing on its strategy to simplify and
optimize the business for a prosperous future
Financial
Stability
Maximize liquidityCredit facility maturing in 2019; Covenants restructured in light of
low commodity prices
Restructure
midstream contractsFinalized new gas gathering agreements in the Haynesville and
dry gas Utica
Divest noncore
assetsNoncore divestitures expected to total $200 – $300mm by 1Q’16;
evaluating substantial noncore assets still in the portfolio
Improve marginsSignificant improvements in LOE and G&A; ~$200mm removed
from cost structure
Operational
Leadership
Base production
optimizationOptimized base production generated an additional 7 mmboe
net vs. 2015 base production forecast
Field development
optimization Chesapeake drilled record laterals in major operating areas
in 2015; significantly enhancing economics
Portfolio Strength
and Flexibility
High-grade and
optimize portfolio
Optimization and reservoir characterization has created a
diverse portfolio with multiple economic investment opportunities
at current prices
Appraise HBP
acreage positionSubstantial progress toward appraising HBP position;
currently appraising Meramec, Oswego and Upper Marcellus
APPENDIX
CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015 17
(1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or diluted earnings per share. Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because:
i. Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.
ii. Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.iii. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the
company generally excludes information regarding these types of items.(2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.
RECONCILIATION OF ADJUSTED
EARNINGS PER SHARE
18CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
($ in mm)
Three Months Ended: 9/30/2015 9/30/2014
Net income available to common stockholders ($4,695) $169
Adjustments, net of tax:
Unrealized (gains) losses on commodity derivatives 58 (384)
Unrealized gains on supply contract derivatives (58) --
Restructuring and other termination costs 44 (9)
Provision for legal contingencies -- 62
Impairment of oil and natural gas properties 4,506 --
Impairments of fixed assets and other 66 9
Net (gains) losses on sales of fixed assets (1) (54)
Repurchase of preferred shares of CHK Utica -- 447
Other (3) 11
Adjusted net income available to common stockholders(1) ($83) $251
Preferred stock dividends 43 43
Earnings allocated to participating securities -- 3
Total adjusted net income attributable to CHK ($40) $297
Weighted average fully diluted shares outstanding(2) 777 776
Adjusted earnings per share assuming dilution(1) ($0.05) $0.38
RECONCILIATION OF ADJUSTED EBITDA
(1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
(2) Ebitda represents net income before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.
(3) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because:
(1) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.
(2) Adjusted ebitda is more comparable to estimates provided by securities analysts.
(3) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
Accordingly, adjusted ebitda should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.
19CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
($ in mm)
Three Months Ended: 9/30/2015 9/30/2014
Cash provided by operating activities $318 $1,184
Changes in assets and liabilities 158 109
Operating cash flow(1) $476 $1,293
Net income ($4,639) $692
Interest expense 88 17
Income tax expense (benefit) (937) 437
Depreciation and amortization of other assets 31 37
Oil, natural gas and NGL depreciation, depletion and amortization 488 688
EBITDA(2) ($4,969) $1,871
Adjustments:
Unrealized losses on oil, natural gas and NGL derivatives 67 (622)
Unrealized gains on supply contract derivatives (70) --
Restructuring and other termination costs 53 (14)
Provision for legal contingencies -- 100
Impairment of oil and natural gas properties 5,416 --
Impairments of fixed assets and other 79 15
Net (gains) losses on sales of fixed assets (1) (86)
Net income attributable to noncontrolling interests (13) (30)
Other (2) 2
Adjusted EBITDA(3) $560 $1,236
CORPORATE INFORMATION
20CITIBANK ENERGY INVESTOR TOUR DECEMBER 2015
PUBLICLY TRADED SECURITIES CUSIP TICKER
3.25% Senior Notes due 2016 #165167CJ4 CHK16
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
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 ir@chk.com
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