CREDIT SUISSE
23RD ANNUAL ENERGY SUMMIT
Vail, Colorado | February 13, 2018
Nick Dell’Osso
Executive Vice President and Chief Financial Officer
Exhibit 99.1
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, guidance 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 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, 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; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt
obligations; 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 to 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 real ized 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/or cyber-attacks adversely impacting our operations; potential challenges by SSE‟s former creditors of our spin-off of 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; the effectiveness of our remediation plan for a material weakness; 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. In addition, this presentation contains time-sensitive information that reflects management‟s best judgment
only as of the date of this presentation.
We use certain terms in this presentation such as “Resource Potential,” “Net Reserves” and similar terms that the SEC‟s guide lines strictly prohibit us from including in filings
with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S.
investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2016, File No. 1-13726 and in our other filings with the SEC, available
from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330.
2 Credit Suisse 23rd Annual Energy Summit
STRATEGIC GOALS
Debt reduction
of $2 – $3 billion
ultimate goal of net debt
to EBITDA of 2X
Free cash flow neutrality
Margin enhancement
2
3
1
OUR STRATEGY AND GOALS
Our strategy remains unchanged –
resilient to commodity price volatility
> Financial discipline
> Profitable and efficient growth
from captured resources
> Exploration
> Business development
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2017 ACCOMPLISHMENTS
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(1) Includes production expenses, general and administrative expenses (including stock-based compensation) and gathering, processing and transportation expenses. Excludes restructuring and other termination costs and interest expense.
(2) Agency reportable spills
~$500 million
Reduced costs by ~18%(1)
Improved cost structure
by ~$0.58/boe
~$1.3 billion
Of net proceeds collected from
asset and property sales
~11% growth
In oil production 4Q16 to 4Q17,
exceeded goal of 10%
~$1.3 billion
Reduced term secured debt by 32%
Continued reduction
in legal complexity
Record EH&S
performance
~0.045 TRIR
15% reduction in reported spills(2)
UPDATE ON RECENT PROGRESS
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(1) Approximately $533 million borrowed on revolving credit facility and includes approximately ~$137mm of letters of credit
(2) Includes proceeds from planned asset sales, FTSI sale of ~4.3 million shares and a positive legal settlement.
Cash proceeds from divestitures
˃ ~$500 million in asset sales signed in late-2017
and 2018; expected to close in 1H 2018
• Represents an EBITDA multiple of 7.1x
˃ ~$73 million in net proceeds from sale of FTSI shares
˃ Pursuing multiple, large transactions
Current liquidity is strong
~$3.1 billion
Revolver availability
as of January 31, 2018 (1)
~$450 million
In pending receipts (2)
WHAT’S THE IMPACT?
(1) Cash costs include production expenses and gathering, processing and transportation expenses.
Sold ~23,000 boe/d (25% oil) while maintaining
flat 2018 adjusted production YOY
Cost structure
reduced by ~$0.14/boe(1)
Interest expense may be reduced by up to ~$50 million
Overhead reduction of ~$70 million through efficiencies and synergies
Remaining FTSI ownership of ~22 million shares
Credit Suisse 23rd Annual Energy Summit 6
+ We expect to be cash flow positive
with signed/closed A&D activity at current strip prices in 2018
$53
$665
$338
$1,300 $1,250
$1,300
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
2015 2016 2017 2018 2019 2020 2021 2022 2023 2025 2026 2027
$2,047
$1,868
$913
Revolving Credit Facility
Secured
Unsecured
Convertibles
$
millio
n
s
$533 million
Revolving Credit Facility
DEBT MATURITY PROFILE
2018 OUTLOOK (1)
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(1) As of 1/31/2018
$9.2 billion
Senior Notes & Term Loan
7.10%
WACD
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˃ Portfolio depth
˃ Growing capital efficiency
˃ Operational scale
˃ Advancing technology
˃ EH&S excellence
Driving value across our portfolio
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(1) Net acreage estimates as of December 31, 2017 and proforma for announced Mid-Continent asset divestitures; 2018 estimated average rig count; PV10 breakeven with oil held flat at $55/bbl and gas held flat at $3/mcf
APPALACHIA NORTH
1 rig
~$1.60 – 2.20/mcf Breakeven
Acreage ~577,000 (86% Held)
MID-CONTINENT
~1 rig
~$30 – 40/bbl Breakeven
Acreage ~806,000 (97% Held)
SOUTH TEXAS
~4 rigs
~$30 – 40/bbl Breakeven
Acreage ~278,000 (97% Held)
GULF COAST
3 rigs
~$2.00 – 2.50/mcf Breakeven
Acreage ~401,000 (90% Held)
ROCKIES
~3 rigs
~$25 – 35/bbl Breakeven
Acreage ~369,000 (55% Held) APPALACHIA SOUTH
2 rigs
~$1.35 – 1.80/mcf Breakeven
Acreage ~2,275,000 (87% Held)
~4.7 million
Net acres
~13,300
Undrilled locations
PREMIER, DIVERSIFIED ASSET BASE
(1)
POWDER RIVER BASIN
GROWING TO A CORE ASSET
• Stacked pay opportunities
˃ ~275,000 net acres in PRB (72% held)
˃ 13+ prospective horizons
• ~2.6 bboe of resource potential;
projected 2022 production of
~200 mboe/d (1)
• Three rigs operating
˃ Plan to ramp to four rigs in 1H 2018
˃ 2018 projected PRB oil growth
of >80% primarily driven by
accelerating Turner development
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Well Status Locations(2)
Producing 208
DUC (3) Inventory 11
Undrilled Inventory 2,780
0
5
10
15
20
0
5
10
15
Q1 2017 Q2 2017 Q3 2017 Q4 2017
E
q
u
iv
al
e
n
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V
o
lu
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(
m
b
o
e/d
)
T
IL
C
o
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t
WY
~40% oil, ~58% liquids
(1) Dependent upon funding level and successful results
(2) Locations as of 12/31/2017
(3) DUC: “Drilled uncompleted” wells
POWDER RIVER BASIN – TURNER
BREAKEVEN: ~$25/BBL(1)
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(1) PV10 breakeven with oil held flat at $55/bbl and gas held flat at $3/mcf
(2) Oil held flat at $55/bbl and gas held flat at $3/mcf
Running room expanding
>600 locations at 1,760' spacing
Over 220 locations with ROR(2)
>100%
Strong performance
Beating industry offsets
Actively reducing capex
11
WY
Cumulative boe vs. Producing Months
Producing Months
Industry Turner Offsets
CHK Turner Producers
400,000
300,000
200,000
100,000
0
C
umula
ti
v
e
b
o
e
2 4 6 8 10 0
CHK TURNER PRODUCERS
TURNER GAS CONDENSATE
TURNER OIL
CHK FEDERAL UNITS
CHK ACREAGE
POWDER RIVER BASIN – NIOBRARA
INCREASED PERFORMANCE THROUGH ENHANCED COMPLETIONS
• First completion test
˃ Increased proppant concentrations
˃ Spacing to 1,320' from 660', ~9,500' lateral
length, 250-day cumulative 208 mboe
• Second completion test
˃ Further increased proppant
˃ 1,320' spacing ~4,500' lateral length,
250-day cumulative 181 mboe
• Third completion test
˃ Learnings from second test,
within volatile oil window
˃ ~6,100' lateral length,
250-day cumulative 280 mboe
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Cumulative boe/ft vs. Time
CHK Niobrara
CHK 2017 DUC
Days Producing
Cu
m
u
la
ti
v
e
b
o
e
/f
t
CHK Combs Ranch 7-33-70 USA B 1H
Peak Rate: 1,650 boe/d (70% oil)
CHK Combs Ranch 17-33-70 ST C 4H
Peak Rate: 1,575 boe/d (46% oil)
CHK NW Fetter 15-33-71 A 6H
Peak Rate: 1,930 boe/d (63% oil)
WY
POWDER RIVER BASIN
PLENTY OF RUNNING ROOM
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205 mmboe resource base
425+ undrilled locations
1,980' spacing
1.2 bboe resource base
600+ undrilled locations
1,760' spacing
67 mmboe resource base
72 undrilled locations
1,980' spacing
538 mmboe resource base
650+ undrilled locations
1,100' – 1,320' spacing
570 mmboe resource base
875+ undrilled locations
1,320' spacing
Parkman
Sussex
Niobrara
Turner
Mowry
Other Future
Potential Formations
Teckla, Teapot, Surrey, Frontier,
Muddy, Dakota/Lakota and
Pennsylvanian
Powder River Basin Acreage 275,000 (72% Held)
WY
0
20
40
60
80
100
120
0
25
50
75
100
Q1 2017 Q2 2017 Q3 2017 Q4 2017
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m
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)
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Well Status Locations(1)
Producing 1,846
DUC (2) Inventory 29
Undrilled Inventory 3,100
SOUTH TEXAS
CONTINUES TO DELIVER
• Large remaining inventory
˃ ~3,100 undrilled locations after updated
development plan
• Stacked pay potential
˃ Upper Eagle Ford and Austin Chalk
provide additional resource potential
• Improved oil recovery
˃ Proven technology
˃ Evaluating multiple pilot opportunities
• ~4 rig program in 2018
˃ Projected reduction of 2018 D&C capex
of ~$150 million provides flat production,
with significantly higher free cash flow
(1) Locations as of 12/31/2017
(2) DUC: “Drilled uncompleted” wells
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TX
~60% oil, ~78% liquids
SOUTH TEXAS
DRIVING FOR VALUE
• Fit-for-purpose completions and targeting
are improving well results
• Right-sized spacing
• Longer laterals optimizing development plan
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Down-spaced wells
2017 Up-spacing test 0
5
10
15
20
25
0 50 100 150 200
C
u
m
u
la
ti
v
e
O
il
/f
t
(bb
l/
ft
)
Producing Days
S Dimmit
+61%
0
5
10
0 50 100 150
C
u
m
u
la
ti
v
e
O
il
/f
t
(bb
l/
ft
)
Producing Days
Four Corners
+44%
NORTH MCMULLEN
0
2
4
6
8
10
12
14
16
0 100 200 300
C
u
m
u
la
ti
v
e
O
il
/f
t
(bb
l/
ft
)
Producing Days
N McMullen
+58%
SOUTH DIMMIT
CHK LEASEHOLD
TX
SOUTH TEXAS – MULTI-ZONE POTENTIAL
TESTING OF UPPER EAGLE FORD AND AUSTIN CHALK
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Austin Chalk
Upper Eagle Ford
Spud 3/17
Spud 6/17
5/17 TIL 4Q17
Pad Level Co-development
Test w/LEFG & UEFG
TIL
3Q17
Pad Level Co-development Test w/LEFG
1Q18 1/17 Spud
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 50 100 150 200
Da
il
y
Prod
u
c
ti
o
n
(b
o
e
/d
)
Days on Production
Blakeway 3 D DIM 2H – Upper Eagle Ford
SERIES2
BLAKEWAY 3 D DIM 2H
PRE-DRILL EXPECTATIONS
TX
BLAKEWAY
Spud: 1Q17
TIL: 5/1/2017
UEGFD
Max Daily Rate 1,900 boe/d
MARCELLUS SHALE
THE PREMIER DOMESTIC GAS BASIN
• Continue to improve
˃ Technology expanding resource recovery,
driving greater value
• FCF generator, capital efficiency
˃ Currently producing ~2.1 bcf/d; minimal
capex required to keep production flat;
7¢/mcf LOE(1)
• Stacked pay
˃ Enhanced completions in Upper Marcellus
compete with Lower Marcellus results;
deeper Utica potential
(1) Gross operated controllable LOE (excluding Ad Val taxes and overhead)
(2) Locations as of 12/31/2017
(3) DUC: “Drilled uncompleted” wells
Credit Suisse 23rd Annual Energy Summit 17
Well Status Locations(2)
Producing 735
DUC (3) Inventory 60
Undrilled Inventory 2,040
0
100
200
0
5
10
15
20
25
30
Q1 2017 Q2 2017 Q3 2017 Q4 2017
E
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(
m
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)
T
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PA
LOWER MARCELLUS
ENHANCED COMPLETIONS DRIVING MORE VALUE
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Operational leader
Breaking records and reducing maintance capital
Record McGavin 6H, IP30 55 mmcf/d
Core expansion
Longer laterals and enhanced completions
deliver greater resource
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 50 100 150 200 250 300 350 400
Cu
m
u
la
ti
v
e
Prod
u
c
ti
o
n
(
M
M
CF
)
Normalized Producing Days
Enhanced vs. Modern Completions
DPH SW WYO 3H MCGAVIN E WYO 6H
WOODMAC MARCELLUS TC
18
Industry Well
37 mmcf/d
CHK OFFSETS
PA
UPPER MARCELLUS
STACKED POTENTIAL
Credit Suisse 23rd Annual Energy Summit
(1) Upper Marcellus development assumes 1,200' spacing
Increasing NAV
Proving potential and increasing locations
~750 locations(1)
Unrealized value
Longer laterals and enhanced completion drive
rival productivity to Upper Marcellus
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 5
1
0
1
5
2
0
2
5
3
0
3
5
4
0
4
5
5
0
5
5
6
0
6
5
7
0
7
5
8
0
8
5
9
0
9
5
1
0
0
1
0
5
1
1
0
G
a
s
F
lo
w
rat
e
(
M
CFD
)
Normalized Producing Days
Maris Wells vs. Expectations
MARIS SUS 25H MARIS SUS 4H PRE-DRILL EXPECATIONS
19
PA
DIVERSE PORTFOLIO PROVIDES OPTIONALITY
(1)
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(1) Net production statistics represent average daily production for 4Q17
Remaining
Undrilled Locations
4Q17
Production
HIGH-MARGIN GROWTH ASSETS
Rockies ~2,780 Locations 18 mboe/d
SIGNIFICANT CASH GENERATING ASSETS
South Texas ~3,100 Locations 112 mboe/d
Appalachia ~2,040 Locations 139 mboe/d
LOW-COST GAS RESOURCE
Gulf Coast ~1,440 Locations 155 mboe/d
Utica Shale ~790 Locations 115 mboe/d
EXPLORATION & DELINEATION ASSETS
Mid-Continent ~3,200 Locations 54 mboe/d
Rome Trough N/A 0 mboe/d
Deep inventory
of high-quality,
high-margin oil
growth assets
and best-in-class
gas assets
Where We Are Going
Reducing leverage
> $2 – $3 billion of debt reduction targeted
> Ultimate goal of 2x debt/EBITDA
Enhancing margins and cash flow
> Attacking all areas of cash costs
> On the path to achieve free cash flow
neutrality in 2018
Focused on capital discipline
> Funding our highest returning projects
> ~13,300 undrilled locations and
continuously high-grading our portfolio
THE EVOLUTION OF CHESAPEAKE
SIGNIFICANT PROGRESS HAS BEEN MADE WITH MORE TO COME
Where We Have Been
GP&T commitments reduced
by ~$6.7 billion since 2014
(~42% decrease)
Dramatically reduced LOE,
G&A and GP&T/boe
Improving capital efficiency
and cost leadership
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Appendix
Credit Suisse 23rd Annual Energy Summit 22
HEDGING POSITION
AS OF 1/31/17
Credit Suisse 23rd Annual Energy Summit 23
As of 1/31/18, does not reflect January 2018 gas settlement
NGL
2018
365 mbbls Propane Swaps $0.73/gal
181 mbbls Ethane Swaps $0.28/gal
255 mbbls Butane Swaps $0.88/gal
Natural Gas
2018
$3.11/mcf
NYMEX
Swaps
Collars
$3.00/$3.25/mcf
NYMEX
47 bcf
532 bcf
Oil
2018
$52.87/bbl
WTI
Swaps
$39.15/$47/$55/bbl
WTI
Collars
1.8 mmbbls
24 mmbbls
• 9.8 mmbbls of 2018 LLS-WTI oil basis hedges @ +$3.33
• 52 bcf of March – October 2018 Tenn Zone 4-300 gas basis hedges @ -$0.77
• 3.3 mmbbls of 2019 oil hedged with swaps at an average price of $56.04
GULF COAST
EXCEPTIONAL DELIVERY
• Unleashing the Haynesville
˃ Enhanced completions resulting in
meaningful NAV improvement
• Unlocking the Bossier
˃ Recent 10,000' Nabors 13&12-10-13 1HC
well peak rate of 35,800 mcf/d
• Significant running room
˃ 30+ years of Haynesville and Bossier
drilling; ~400+ potential refrac opportunities
• Three rig program in 2018
˃ Projected reduction in 2018 D&C capital of
~$75 million provides flat production, but
significantly higher free cash flow
(1) Locations as of 12/31/2017, excludes potential refrac opportunities
(2) DUC: “Drilled uncompleted” wells
Credit Suisse 23rd Annual Energy Summit 24
Well Status Locations(1)
Producing 630
DUC (2) Inventory 18
Undrilled Inventory 1,440
0
20
40
60
80
100
120
140
160
180
0
5
10
15
20
Q1 2017 Q2 2017 Q3 2017 Q4 2017
E
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LA
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0 2 4 6 8 10 12 14
A
v
e
rage
C
u
m
u
lati
v
e Gas
p
e
r
W
el
l
(b
cf
)
Month
Average Cumulative Gas per Well
„08 – „09
„10 – „13
„14 – „15
„16
„17
HAYNESVILLE
COMPETITIVE ADVANTAGE
Credit Suisse 23rd Annual Energy Summit
2008 – 2013
HBP Position
2014 – 2015
Develop Core Position
2016
Longer Laterals,
Enhanced Completions,
Increased IP‟s
2017
Area Specific Completions,
Improved Capital Efficiency,
Optimized Drawdown
25
LA
Gulf Coast Acreage 401,000 (90% Held)
HAYNESVILLE
PARADIGM SHIFT
Credit Suisse 23rd Annual Energy Summit
Two pads, 134 mmcf/d
BSNR 1H – 37 mmcf/d w/ 9,800' LL
BSNR 2H – 32 mmcf/d w/ 9,800' LL
BSNR 3H – 35 mmcf/d, w/ 9,800' LL
BSNR 4H – 30 mmcf/d, w/ 9,800' LL
Continuing to push the envelope
More to do…
Strong across the field
26 wells with IP 30 greater than 30 mmcf/d
26
LA
15,000' Laterals Bossier
Development
Unlocking
Refrac Potential
BOSSIER
UNLOCKED POTENTIAL
Credit Suisse 23rd Annual Energy Summit 27
Nabors 13&12-10-13 1HC
TIL 11/17/2017 ~10,000' lateral
Peak rate – 35,800 mcf/d
47-day cumulative – 1.39 bcf
• Longest horizontal and largest completion
˃ First 10,000' lateral drilled and completed
˃ Reduced cluster spacing with 4,500 lb./ft.
• Exceptional reservoir quality and pressure
LA
Cumulative Production – Normalized for LL
Producing Days
C
u
m
u
lati
v
e
P
ro
d
u
cti
o
n
(
m
m
cf/
ft
)
Nabors 13&12-10-13 1HC
Other Bossier Wells
APPALACHIA SOUTH
VALUE FOCUS
• Enhanced completions
˃ Improving cumulative production, while
continuing to optimize well spacing
• Two rig program in 2018
˃ ~10% increase in projected 2018 gas
production from flat capex
• Untapped potential
˃ Rome Trough offers three-stream potential
over ~1.4 million net acres
(1) Locations as of 12/31/2017
(2) DUC: “Drilled uncompleted” wells
Credit Suisse 23rd Annual Energy Summit 28
Well Status Locations(1)
Producing 704
DUC (2) Inventory 28
Undrilled Inventory 790
0
20
40
60
80
100
120
140
0
5
10
15
20
25
30
35
Q1 2017 Q2 2017 Q3 2017 Q4 2017
E
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m
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OH
~10% oil, ~31% liquids
UTICA
DRY GAS PERFORMANCE
Credit Suisse 23rd Annual Energy Summit
Optimizing design
~20% improvement in 90-day cumulative production
Continue to test economic bounds
29
High Yield Completion Performance
Producing Days
C
u
m
u
lati
v
e
P
ro
d
u
cti
o
n
(
m
m
cf
)
Enhanced Design
Type Curve
Base Design
OH
Acton
2 Well Pad
Avg IP/well – 13.8 mmcf/d
Dec TIL
Schiappa Trust A
3 Well Pad
Avg IP/well – 21.2 mmcf/d
Nov TIL
Bozich
4 Well Pad
Avg IP/well – 18.2 mmcf/d
Nov TIL
High Yield Completion Performance
Producing Days
C
u
m
u
lati
v
e
P
ro
d
u
cti
o
n
(
b
o
e
)
Enhanced Completions
Type Curve
Base Design
UTICA
WET GAS PERFORMANCE
Credit Suisse 23rd Annual Energy Summit
Enhanced completions
~15 – 20% improvement in 180-day cumulative production
Continuing to optimize design and well spacing
ELLIE
8 Well Pad
Avg IP/Well – 1100 boe/d
65% liquids
July TIL
DONALD
3 Well Pad
Avg IP/Well – 870 boe/d
61% liquids
Dec TIL
OUR LAND CO
2 Well Pad
Avg IP/Well – 1340 boe/d
64% liquids
June TIL
30
OH
MID-CONTINENT
~810,000 NET ACRES OF STACKED PAY POTENTIAL
• Oil growth potential
˃ Oswego provides low-cost, high-return oil,
while commencing drilling in Chester, Hunton
• Plan forward in 2018
˃ One rig dedicated to Oswego
˃ Chester, Hunton appraisal
(1) Locations as of 12/31/2018
(2) DUC: “Drilled uncompleted” wells
Credit Suisse 23rd Annual Energy Summit 31
Well Status Locations(1)
Producing 3,165
DUC (2) Inventory 12
Undrilled Inventory 3,200
0
10
20
30
40
50
60
0
5
10
15
20
25
30
Q1 2017 Q2 2017 Q3 2017 Q4 2017
E
q
u
iv
al
e
n
t
Ne
t
V
o
lu
m
e
(
m
b
o
e
/d
)
T
IL
C
o
u
n
t
OK
CHESTER PLAY
THE NEXT STACKED PLAY
• Transforming a vertical play with
technology
˃ ~2.2 bboe mean resource potential
˃ 8+ stacked reservoir targets
˃ Proven potential with 9,000+
vertical wells
˃ Industry activity 50% oil
˃ EUR with standard completion:
~370 mboe (10,000')
• Dominant land position
˃ Largely contiguous position with
~600,000 net acres; 97% HBP
˃ 1,000+ locations in inventory for
extended laterals (10,000')
Credit Suisse 23rd Annual Energy Summit 32
OK
Ragan 2820 3-22H
90 Day CUM = 61 mboe
64% liquids
CHK
Wonderland 5&8 23-14 1H
Core Test Well
CHK
Gold Star 25-25-18
Core Test Well
MID-CONTINENT OSWEGO
LOW-COST, HIGH-RETURN OIL VOLUME
Credit Suisse 23rd Annual Energy Summit
Price Deck: $3/mcf and $55/bbl oil flat
Quick turnaround
40 – 50 day spud to TIL cycle time
Drill and TIL 25 – 30 wells in 2018
40 MILES
4
0
M
IL
E
S
33
0
2
4
6
8
10
12
14
16
0–100 100–200 200–300 300–400 400–500 500–600 600–700
W
el
l C
o
u
n
t
EUR, mboe
EUR Frequency Plot
Low cost
$3.7 per well D&C cost
650 boe/d avg IP30
High return
>60% rate of return core wells
300 mboe EUR (83% liquids)
CORPORATE INFORMATION
Credit Suisse 23rd Annual Energy Summit
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
34
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