INVESTOR RELATIONS UPDATE January 2017
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 this presentation, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law.
INVESTOR RELATIONS UPDATE – JANUARY 2017
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HAYNESVILLE DIVESTITURES ACCELERATING VALUE • Signed PSA to divest multiple Haynesville assets for total of $915mm ˃ Both sales expected to close in 1Q 2017 ˃ Proceeds continue progress towards strategic target of $2 – $3 billion in debt reduction
• Gross proceeds from asset divestitures signed or closed of $2.5 billion in 2016
8 – 10 Development program years of extended lateral drilling remaining after planned divestitures
Play Statistics Current
Post Divestitures
Undrilled
2,070
1,425
Acreage
~385,000
~255,000
Production
1.2 bcf/d
1.1 bcf/d
INVESTOR RELATIONS UPDATE – JANUARY 2017
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OUR STRATEGY RELEVANT THROUGH COMMODITY PRICE CYCLES
Financial Discipline > Balance capital expenditures with cash flow from operations
Profitable and Efficient Growth From Captured Resources > Develop world-class inventory
> Increase financial and operational flexibility
> Target top-quartile operating and financial metrics
> Achieve investment grade metrics
> Pursue continuous improvement > Drive value leakage out of operations
Business Development
Explore
> Optimize portfolio through strategic divestitures
> Leverage innovative technology and expertise
> Target strategic acquisitions
> Explore and exploit new growth opportunities
> Enhance and expand the portfolio
INVESTOR RELATIONS UPDATE – JANUARY 2017
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Differential Business Improvement
Operational Focus In 2017
Strategic Targets In 2017 And Beyond
CHK IS POSITIONED TO OUTPERFORM
Where we have been 2012 – 2016
Where we are going
Strengthened the balance sheet, reduced complexity and legacy commitments
Leverage portfolio strength and depth to drive efficient growth and further improve debt metrics (3)
2016 – 2020
~50% reduction
~50% reduction
2x
In total leverage (1)
In cash costs per boe (2)
= $10.9 billion
= $4.10/boe in 2016E
5% – 15%
Net debt/EBITDA
Annual production growth
Cash flow neutrality achievable in 2018 Based on 2017 investment (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
INVESTOR RELATIONS UPDATE – JANUARY 2017
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UNRECOGNIZED VALUE, UNLOCKED POTENTIAL POWER OF THE PORTFOLIO
11.3 BBOE Total net recoverable resources
5,600 locations Above 40% ROR (1)
> Risked locations > Downspacing upside
> Proven reservoirs > Tremendous exploration and technology upside
(1) Economics run at $3/mcf and $60/bbl oil flat
INVESTOR RELATIONS UPDATE – JANUARY 2017
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Differential Business Improvement
Operational Focus In 2017
Strategic Targets In 2017 And Beyond
SOUTH TEXAS ASSET OVERVIEW UNDRILLED ACREAGE, POSITIONED FOR GROWTH
• Secure acreage position
~270,000 Net Acres in Eagle Ford – 99% HBP/ HBO
• Best-in-class operations • Extended laterals are working
3 – 4 rigs Active in 2017 Austin Chalk 1,000
Locations
Production Mix (1)
Upper Eagle Ford 1,000 Drilled 25%
Lower Eagle Ford 3,260
Remaining Development 75%
25% 56% 19%
Oil
NGL
Natural Gas
(1) Net processed production mix
INVESTOR RELATIONS UPDATE – JANUARY 2017
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ACCELERATING VALUE USING EXTENDED LATERALS CURRENT EAGLE FORD RESULTS BEATING TYPE CURVE EXPECTATIONS
West Four Corners Performance
Beating the type curve
160
11 of 13 extended lateral wells are outperforming the type curve
Cumulative Oil Production (mbo)
Extended Lateral Wells (>9,000') Avg. Extended Lateral Performance 10,000' Lateral Type Curve 5,000' Lateral Type Curve
120
Value acceleration Extended laterals provide 2-for-1 NPV
80
Cumulative 10% Discounted Cash Flow, $(mm) Two 5,000' Laterals
Single 10,000' Lateral
$2.0 $1.0
40
$0.0 0
1
2
3
4
-$1.0
5
Years
-$2.0
0 0
40
80
120
Production Days
160
200
-$3.0
Expected payout in
-$4.0
< 2 years
-$5.0
Due to XL strategy execution
INVESTOR RELATIONS UPDATE – JANUARY 2017
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TRANSFORMING THE LOWER EAGLE FORD EXTENDED LATERALS UNLOCK VALUE IN LOW PRICE ENVIRONMENT
Well Cost vs. Production IP (1) 1,800 Lazy A Cotulla G 4H LL: 10,547'
1,600
Lazy A Cotulla G 5H LL: 10,563'
Production IP (boe/d)
1,400 Lazy A Cotulla G 3H LL: 10,523'
1,200
1,000
Valley Wells C 4H LL: 9,778'
Valley Wells C 6H LL: 9,180'
2016: 10,000' TC laterals
800
2016: 6,500' TC laterals 2015: 6,500' TC laterals 2014: 5,000' TC laterals
600
400
200
0 $2.0
$3.0
$4.0
$5.0
$6.0
$7.0
Well Cost ($mm) (1) Assumes $3/mcf gas price flat
INVESTOR RELATIONS UPDATE – JANUARY 2017
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SOUTH TEXAS WELL POSITIONED TO GROW 300
35
30
25 200 20 150 15
Gross Rig Count
Gross Operated Production, mboe/d
250
100 10
50
5
0 2011 Rig Count
0 2012 2011
2013 20122016E
2014 2013
2015 2015 2014
2016 2016E 2015
2017 2017E 2016E
2018 2018E 2017E
INVESTOR RELATIONS UPDATE – JANUARY 2017
2018E
12
MID-CONTINENT BRIDGE TO OIL GROWTH
• Shift from historical plays to new concepts and formations
~1.5mm Net Acres in Mid-Continent
• Legacy acreage position offers extensive opportunity
• Oswego – a bridge to oil production growth • Actively exploiting “The Wedge” opportunity
3 – 4 rigs Active in 2017
INVESTOR RELATIONS UPDATE – JANUARY 2017
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OSWEGO DELIVERING IMPRESSIVE RESULTS 40 MILES Lightle 4-18-6 1H IP 30 = 1,098 bo/d IP 30 = 1,235 boe/d
Hasty 3-18-6 1H IP 30 = 897 bo/d
$3.0mm/well
IP 30 = 1,033 boe/d
Development cost
~400 mboe EUR
Farrar 11-18-6 1H IP 30 = 727 bo/d
83% liquid, average WI 53%
IP 30 = 852 boe/d
40 MILES
Hughes Trust 33-18-7 1H IP 30 = 1,257 bo/d
Caldwell 22-18-6 1H IP 30 = 1,447 bo/d
IP 30 = 1,326 boe/d
12%
IP 30 = 1,813 boe/d
17%
Themer 6-17-6 1H IP 30 = 717 bo/d IP 30 = 832 boe/d
71% Oil
NGL
Natural Gas
INVESTOR RELATIONS UPDATE – JANUARY 2017
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THE WEDGE PLAY
CHESAPEAKE’S FUTURE MID-CONTINENT GROWTH ASSET Strong economics – large land position • ~870,000 net acres Sharon 31-27-11 1H IP: 2,062 boe/d
˃ 94% HBP
• Robust economics ˃ ~500 locations at 50% ROR (1,2)
• Significant running room ˃ ~1,400 additional upside locations
McCray 2414 1-10H/15H IP: 1,267 boe/d
Ward 21-1H IP: 596 boe/d School Land 1-36H IP 30: 1,353 boe/d
• Efficient capital spend ˃ Industry actively de-risking plays
Howard 5-19-17 1H IP: 2,454 boe/d Whistle Pig 10-4AH IP 30: 719 boe/d
TWO New Wedge step-out tests
1,000 – 1,500 boe/d (50 – 70% oil) One mile laterals with opportunity for two mile development
Anderson 1206 1-33WH IP: 745 boe/d
Governor James B. Edwards IP 30: 1,684 boe/d
(1) Location counts exclude Miss Lime locations (2) Price deck: $3/mcf for gas and $60/bbl oil flat
INVESTOR RELATIONS UPDATE – JANUARY 2017
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MID-CON GROWTH ENGINE SCALABLE GROWTH FROM OSWEGO AND THE WEDGE
140
Gross Operated Production, mboe/d
120
100
80
60
40
20
0 06/2016
06/2017 1 – 4 Rigs
Oswego
Oswego Gen 3 Completion
06/2018
06/2019
06/2020
4 – 8 Rigs
Miss Lime Development
Wedge Development
Development model only reflects the first 100 Oswego locations
INVESTOR RELATIONS UPDATE – JANUARY 2017
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GULF COAST WORLD-CLASS RESOURCE • CHK Haynesville position is 100% HBP and only 25% developed • Unique opportunity to develop field with newest technology
Future Returns of the Gulf Coast (1) ~70%
50% 27%
2Q '16
10,000' Laterals w/ Modern Completion
10,000'+ Lateral w/ 3,000'+ lbs./ft. Completion
2016E
2017+
2 – 3 rigs Active in 2017
(1) Assumes $3 mcf gas price
INVESTOR RELATIONS UPDATE – JANUARY 2017
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HAYNESVILLE GAME-CHANGING PERFORMANCE LONGER LATERALS AND BIGGER COMPLETIONS
New CHK wells delivering monster IPs
3.5
Cumulative Production (bcf)
3
CA 1H – 38 mmcf/d, 10,000' lateral PCK 1H – 31 mmcf/d, 7,000' lateral WILL 1H – 34 mmcf/d, 8,350' lateral
3.0
2.5
2
1.6 1.5
1.2 1
>250% increase
0.8
In 90-day production with extended laterals, increased proppant loading and reduced cluster spacing
0.5
0 0
20
40
60
80
100
120
140
Producing Days
INVESTOR RELATIONS UPDATE – JANUARY 2017
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RETURNING TO POWDER RIVER BASIN ONE MILE OF OPPORTUNITY • ~2.7 bboe gross recoverable resource potential • ~2,600 risked locations • Renegotiated midstream unlocks value
Teapot
• The next oil growth asset
Parkman E, A, B/C & Deep
˃ CHK rig returned to the basin in November
Surrey
Net Production Potential 120
Sussex
100 2016E CHK Eagle Ford Equivalent
Niobrara mboe/d
80
Oil
NGL
Natural Gas
Turner 60
Frontier Mowry
40 20 2017E
2018E
2019E
1–2 Rigs
2020E
2021E
2022E
4+ Rigs INVESTOR RELATIONS UPDATE – JANUARY 2017
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SUSSEX SANDSTONE HIGHLY ECONOMIC OIL PLAY • Moving to development • Dominant position in the play
Teapot
• ~200 undrilled locations
Parkman E, A, B/C & Deep
˃ Assumes 1,320' spacing
˃ Overpressured – high deliverability
Surrey
• Targeted development Sussex
˃ EUR: 825 – 1,350 mboe ˃ ROR: 50 – 70% (1)
Niobrara
˃ 2017 focused drilling program
Production Mix
Turner Frontier
Oil breakeven price
Mowry
35%
(2)
53%
10,000' lateral length where possible
INVESTOR RELATIONS UPDATE – JANUARY 2017
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MARCELLUS PRODUCTION STRENGTH SUSTAINABLE PRODUCTION WITH MINIMAL CAPITAL
• DUC focus in 2017 and 2018 > Exceptional point forward economics
> 11 obligatory spuds through 2018
Remarkable productivity Minimal capital required
Gross Daily Production (mmcf/d)
• Minimal obligations
Base Producing Wells Includes curtailed volumes No D&C capital spend required
INVESTOR RELATIONS UPDATE – JANUARY 2017
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FLEXIBLE INVESTMENT OPPORTUNITIES STRENGTH IN OPTIONALITY – UTICA
• High-quality and diverse position • Market advantages
$4.00
$80
$3.50
$70
$3.00
$60
$2.50
$50
Drilled 30% Remaining Development 70%
$2.00 0%
~$200mm
$40 150%
50% 100% Rate of Return DRY TYPE CURVE
WET TYPE CURVE
Projected free cash flow through 2018 (1) (1) Assumes $3 / $48 for 2017 and $3 / $60 in 2018, excluding hedges
INVESTOR RELATIONS UPDATE – JANUARY 2017
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Oil Price $/bbl
Location Count
Gas Price ($/mcf)
• 1 – 2 rigs planned in 2017
DRY GAS GROWTH UTICA SHALE
Utica Dry Locations
Remaining Development 90%
>40% ROR Average CHK WI ~ 90% (1)
Gas Production mmcf/d
Drilled 10%
Utica Dry Production (mmcf/d)
>350% Production growth
$2.14 Per mcf Utica Dry PV10 breakeven
~93% of dry gas is sent to Gulf market
(1) Assumes $3/mcf gas flat
INVESTOR RELATIONS UPDATE – JANUARY 2017
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ADJUSTED PRODUCTION RECONCILIATION CUMULATIVE IMPACT OF MULTIPLE SALES TRANSACTIONS IN 2016 Production with Divestiture Adjustments (1) Full impact of Barnett and planned Devonian and Haynesville divestitures
800 700
Mid-Continent divestitures close
Partial quarter impact of Barnett Shale exit
600
(mboe/d)
500 400 300 200 100 0 3Q'16
Total Production
4Q'16
(2)
Divested Liquids Volume
1Q'17
Divested Gas Volume
(1) 3Q’16 divestiture production impact of 8,200 bo/d, 102mmcf/d and 5,900 bbl/d of NGL. 4Q’16 projected divestiture production impact of 8,300 bo/d, 310 mmcf/d and 7,200 bbl/d of NGL. 1Q’17 projected divestiture production impact of 8,500 bo/d, 495 mmcf/d and 8,100 bbl/d of NGL. (2) Projected total production volumes represent the mid-point of guidance provided on page 5.
INVESTOR RELATIONS UPDATE – JANUARY 2017
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(2)
DEBT MATURITY PROFILE • Pro forma tender results, OMRs, 6.25% Euro note maturity and 6.50% 2017 redemption
INVESTOR RELATIONS UPDATE – JANUARY 2017
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HEDGING POSITION
Natural Gas
Oil
2017
2017 (1)
(1)
3% Collars
$3.00/$3.48/mcf NYMEX
71% 68% Swaps
68% $3.07/mcf NYMEX Swaps $50.19/bbl
~120 bcf hedged in 2018 with swaps at an average price of $3.13 ~47 bcf hedged in 2018 with collars at an average price of $3.00/$3.25
(1) As of 1/15/17, using midpoints of total production from 11/3/2016 Outlook
INVESTOR RELATIONS UPDATE – JANUARY 2017
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