UBS Global Oil and Gas Conference Presentation

1 I UBS Global Oil and Gas Conference 5/19/2015

UBS GLOBAL OIL AND GAS CONFERENCE

MAY 19, 2015


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 that give our current expectations or forecasts of future events. They

include production forecasts, estimates of operating costs, assumptions regarding future natural gas and liquids prices, planned drilling activity, anticipated asset sales

and related adjustments, reductions in leverage, estimates of future capital expenditures, estimates of recoverable resources, projected rates of return and expected

efficiency gains, as well as projected cash flow, inventory levels and capital efficiency, business strategy and other plans and objectives for future operations. 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.

• 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 estimates and underlying market prices are subject to significant volatility. Our production forecasts are 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. References to “EUR” (estimated ultimate recovery) and “resources” include estimates of quantities of natural gas, oil and NGL we believe will ultimately be

produced, but that are not yet classified as “proved reserves,” as defined in SEC regulations. Estimates of unproved resources are by their nature more speculative

than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by Chesapeake. We believe our estimates of

unproved resources are reasonable, but our estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly

as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

• 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.


STRONG STRATEGIC POSITION

High-quality assets

Talented people

Superior capital efficiency

Industry-leading cash costs

Strong liquidity

CHK


1Q’15 FINANCIAL & OPERATIONAL RESULTS

PROD. and G&A EXP. ADJ. EARNINGS/FDS ADJ. EBITDA

5% YOY

$5.75/boe(1)

$ 928 mm $ 0.11

(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 22-23

14% YOY

686 mboe/d(2)

LIQUIDS MIX(3) ADJ. OIL PRODUCTION

29% 17% YOY

122 mbbls/d

of Total Production

ADJ. PRODUCTION


EAGLE FORD LOW-COST VALUE GENERATION

• 1Q’15 operational updates

˃ 600 – 700 incremental wells added to undrilled inventory following successful down spacing tests

˃ First 5 wells with 10,000’+ laterals drilled in 1Q’15

˃ 7% sequential production increase to 113 mboe/d

˃ Currently at seven rigs, transitioning to 3 by 2Q’15

˃ 105 1Q’15 TILs had average peak rate of 763 boe/d

• Strategic priorities

˃ Take advantage of lower activity levels to optimize field development planning

˃ Front-loaded development planning with focus on prioritizing wells with >10,000’ laterals

˃ Incorporate tighter well spacing into development plan, avoiding lost opportunities

$8.1

$6.9

$5.9 $5.5

2012 2013 2014 2015

Well Cost ($ in mm)

E


EAGLE FORD SPACING TEST RESULTS

• No appreciable production impact from

reduced spacing

• Increased drillable locations by 600 – 700

to ~4,500 total Lower Eagle Ford locations

• Additional down spacing tests planned

6

Four Corners

Oil Area McMullen

Oil Area

Southern

Wet Gas Area

~120 Incremental Wells



0

20

40

0 30 60

Cu

mu

lati

ve O

il (m

bo

) McMullen Oil Area

500' Spacing

330' Spacing

0

50

100

0 100 200 300 400

Cu

mu

lati

ve O

il (m

bo

)

Four Corners Oil Area 500' Spacing

360' spacing

0

25

50

0 100 200

Cu

mu

lati

ve O

il (m

bo

) Southern Wet Gas Area

660' Spacing

500' Spacing


EAGLE FORD DRIVING CAPITAL EFFICIENCY WITH LONGER LATERALS

• Field development planning focused on prioritizing longer lateral wells

• Successfully drilled five wells with laterals >10,000’ in 1Q’15

• One 10,000’ lateral well pays out twice as fast as two 5,000’ lateral wells

33% Decrease in cost per foot

76% Improvement in EUR with 10,000’ laterals

~600 Potential number of locations with lateral lengths > 10,000’

439 588

772

$12.30

$10.71

$9.33

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

-100

100

300

500

700

900

1100

Four Corners5,000'

Four Corners7,500'

Four Corners10,000'

EUR (mboe)

Well Cost / EUR ($/boe)

1,080

840

720

Four Corners5,000'

Four Corners7,500'

Four Corners10,000'

Well Cost / Lateral Foot($ / ft.)


HAYNESVILLE STRATEGIC DEVELOPMENT DRIVES VALUE CREATION

7,500’ Lateral Test

Enhanced Haynesville completions

Enhanced Bossier completions


˃ Two 7,500’ lateral tests flowing an average of

17 mmcf/d

˃ Doubled commercial Haynesville area

˃ Commercialization of the Bossier Shale

˃ 4% sequential production increase to 616 mmcf/d

˃ 17 1Q’15 wells had average peak rate of

15.4 mmcf/d

˃ Six rigs currently, dropping to three by YE’15


˃ Transition to 100% implementation of enhanced

stimulation technique

˃ Prioritize Haynesville and Bossier development

with 7,500’ laterals

˃ Testing 10,000’ design in 4Q’15


HAYNESVILLE BREAKING THROUGH DEVELOPMENT BARRIERS

• 7,500’ lateral test results

˃ Wells located in traditional 6 – 8 bcf

contour interval

˃ Production test exceeds offsets by

more than 8 mmcf/d

$8.2mm Field estimated D&C cost


MISSISSIPPIAN LIME CONSISTENTLY OUTPERFORMING EXPECTATIONS


˃ 11% sequential production increase to 32 mboe/d net

˃ Currently running three rigs & one completion crew

˃ 48 wells brought online in 1Q’15 had average peak rate of 733 mboe/d

˃ Positive new formation tests in the Oswego and Hoxbar


˃ Expand drillable inventory via capital efficiencies and delineation drilling

˃ Test new horizons currently not within the active development programs

˃ Focus on reducing base decline through artificial lift and recompletions

24 26

27 28

32

1Q'14 2Q'14 3Q'14 4Q'14 1Q'15

Net Production (mboe/d)


MISSISSIPPIAN LIME LEADING THE INDUSTRY

• 45% capital reduction projected from 2012 to 2015

• 2015 development program generates 39% ROR at $2.5 mm(1)

• Capital efficiency improvements and field delineation program continue to

generate incremental core locations

30%

39%

52%

$2.25$2.50$2.75

D&C Cost ($ in mm)

Core Development Economics $4.6

$3.5

$3.1

$0.22 $0.18

$0.20 $2.5

2012 2013 2014 2015

Supply

Chain Efficiency

Gains Design

Improvements

Miss Lime CAPEX per Well ($ in mm)

E

(1) Based on $3.25/mcf gas and $65 /bbl oil


• High quality legacy position

˃ ~74,000 net acres with stacked pay

˃ ~91% of acreage is held by production

˃ >147 potentially operated sections

• Inventory

˃ Industry activity continues to de-risk locations

˃ >440 locations identified within the Meramec oil fairway (>50% oil)

˃ Expect Meramec testing to begin in Q4 2015

• Upside

˃ Woodford and Hunton

˃ Currently testing Oswego

NORTHERN MID-CONTINENT MERAMEC POTENTIAL

Oil Line

Extents of Meramec Play

Industry Meramec Well

CHK Acreage

1723 BOEPD IP

(85% Oil) 1374 BOEPD IP

(80% Oil)

1309 BOEPD IP

(79% Oil)

Oil

Gas &

Condensate


NORTHERN MID-CONTINENT OKLAHOMA OIL GROWTH OPPORTUNITIES

• Stacked plays with proven strong

Horizontal results

• ~6,000 potential locations in ~2,000 CHK

controlled sections

• To date CHK has only realized value for

Miss Lime

Formation

Acre

s

Only ~33% (365M acres) of Chesapeake’s

acreage is assigned to Miss Lime

1.1 million Total Net Acres

Formation


UTICA 2015 STRATEGIC FOCUS


˃ Five rigs currently; two rigs by middle

of 3Q’15

˃ Four frac crews currently; 2.5 on

average for remainder of year

˃ Minimum two rigs to hold acreage


˃ Reduce WOC/WOPL well inventory

˃ Focus on capital efficiency via

industry-leading operations

˃ Limit testing to expand core resources

˃ Optimize base production

CHK/TOT JV Outline CHK Operated Rigs Industry Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window


~25% Expected rate of return based on actual results at $3.25 gas / $65 oil

UTICA IMPROVING PERFORMANCE LEADS TO CORE EXPANSION

• Optimized completions

• Enhanced geologic interpretation

˃ Targeting

˃ Fault identification

˃ Pressure mapping

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

0 100 200 300 400

Gro

ss B

oe/d

Days

Columbiana County Well Results

Early Wells

New Wells

Expected Type Curve

CHK/TOT JV Outline CHK Leasehold Oil Window Wet Gas Window Dry Gas Window

+50% Improvement in new well performance vs. early wells

3 Wells

9 Wells


POWDER RIVER 2015 STRATEGIC FOCUS


˃ One rig current through YE’15

˃ One frac crew currently; limited crews

remainder of year

˃ Federal Units limit amount of activity needed

to hold acreage


˃ Primarily focused on Sussex

˃ Niobrara resource expansion

˃ Continuing to drive efficiencies

˃ Huge resource potential via stacked plays

(1) Includes Teapot, Parkman, Sussex and Shannon

(2) Includes stacked, staggered laterals and Niobrara core expansion, Frontier and Mowry

> 2.0 billion boe Gross recoverable resources

Gross Unrisked Resources

3,000+ Potential gross locations

(1)

(2)


-

100

200

300

400

500

600

700

-

200

400

600

800

1,000

1,200

- 1 2 3

Cum

ula

tive P

roductio

n (

mboe)

Avera

ge b

oe/d

End of Year

POWDER RIVER SUSSEX PERFORMANCE

Sussex Performance

Sussex Drilled Wells Peak 24-Hour Rates

14 days Recent spud to rig release record $3.2mm drilling cost ($1 mm savings)

8,950’ Recent completed lateral length with record stages of 30

800 mboe gross EUR type curve (63% Oil)

950 boe/d first month average

Sussex

Parkman

Teapot

Frontier

Niobrara

CHK Leasehold

Mar 2015 TIL Peak 1,990 boe/d

(68% Oil)

Feb 2014 TIL Peak 1,420 boe/d

(75% Oil)

Jan 2014 TIL Peak 2,900 boe/d

(50% Oil)

Jul 2014 TIL Peak 1,000 boe/d

(88% Oil)

20% – 50% Expected rate of return at $3.25 gas / $65 oil

Type Curve Average Rate

Type Curve Cumulative Production

Current Performance Average Rate

+100%


-

2

4

6

8

10

12

14

16

18

0

50

100

150

200

250

300

1Q'15 2Q'15E 3Q'15E 4Q'15E

Fra

c C

rew

s

Well C

ou

nt

Completion Activity

TIL Frac Crews

-

10

20

30

40

50

60

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1Q'15 2Q'15E 3Q'15E 4Q'15E

$ in

billio

ns

D&C Capex and Rig Count

D&C Capex Reduction from Feb'15 Rigs

• = Actual 1Q’15 results

LOWER 2015 CAPEX AND ACTIVITY

Note: Data above based on Outlook issued 5/6/2015

• ~45% reduction in total capex vs. 2014; >30% reduction in D&C capex

• ~$6 billion of budgeted liquidity at YE’15 with a combination of cash on balance

sheet and an undrawn credit facility


STRONG STRATEGIC POSITION

High-quality assets

Talented people

Superior capital efficiency

Industry-leading cash costs

Strong liquidity

CHK

20 I UBS Global Oil and Gas Conference 5/19/2015 20 I UBS Global Oil and Gas Conference 5/19/2015

APPENDIX


Utica 3 – 5 3 – 5 2 – 3

REDUCED ACTIVITY LEVELS

2015E Avg.Op Rigs

(2/25 Outlook)

Eagle Ford 12 – 14 8 –10 2 – 4

Haynesville 7 – 8 5 – 6 2 – 4

PRB: Niobrara & Upper Cretaceous 3 – 4 2 – 3 1 – 2

Mississippian Lime 7 – 8 5 – 6 2 – 4

Mid-Continent South 1 – 2 1 – 2 0 – 1

Marcellus 1 – 2 1 – 2 0 – 1

Other(1) 1 – 2 0 – 1 –

Total 35 – 45 25 – 35 9 – 19

(1) Other includes Cleveland Tonkawa, Barnett

2015E Avg.Op Rigs

(3/23 Outlook)

YE 2015 Op. Rigs

(3/23 Outlook)


($ in mm)

Three Months Ended: 3/31/2015 3/31/2014

Net income available to common stockholders $(3,782) $374

Adjustments, net of tax: Unrealized gains on derivatives 192 80

Restructuring and other termination costs (7) (4)

Provision for legal contingencies 18 --

Impairment of oil and natural gas properties 3,635 --

Impairments of fixed assets and other 3 12

Net (gains) losses on sales of fixed assets 2 (14)

Net gain on sales of investments -- (42)

Losses on purchases of debt and extinguishment of other financing -- --

Tax rate adjustment (17) --

Other (2) (1)

Adjusted net income available to common stockholders(1) $42 $405 Preferred stock dividends 43 43

Earnings allocated to participating securities -- 8

Total adjusted net income attributable to CHK $85 $456

Weighted average fully diluted shares outstanding(2) 776 767

Adjusted earnings per share assuming dilution(1) $0.11 $0.59

(1) Adjusted net income 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


($ in mm)

Three Months Ended: 3/31/2015 3/31/2014 Cash provided by operating activities $423 $1,291

Changes in assets and liabilities 487 332

Operating cash flow(1) $910 $1,614

Net income $(3,720) $466

Interest expense 51 39

Income tax expense (1,372) 280

Depreciation and amortization of other assets 35 78

Oil, natural gas and NGL depreciation, depletion and amortization 684 628

EBITDA(2) $(4,322) $1,491

Adjustments:

Unrealized gains on oil, natural gas and NGL derivatives 274 144

Restructuring and other termination costs (10) (7)

Impairments of fixed assets and other 25 --

Net gains on sales of fixed assets 4,976 --

Losses on investments 4 20

Net (gain) loss on sales of investments 3 (23)

Losses on purchases of debt and extinguishment of other financing -- (67)

Provision for legal contingencies -- --

Net income attributable to noncontrolling interests (19) (41)

Other (3) (2)

Adjusted EBITDA(3) $928 $1,515

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.


MISSISSIPPIAN LIME IMPROVED KNOWLEDGE DRIVES PERFORMANCE

280 295

335

2012 2013 2014

Operated Mississippian Lime EUR (mboe)

0

100

200

300

400

500

2 6 10 14 18 22 26 30 34

Dai

ly P

rod

uct

ion

(b

oe/

d)

Normalized Time (Months)

2012

2013

2014

• Significant well performance

improvement over the last

three years

˃ Completion optimization

˃ Balanced rig program of core and

delineation wells

˃ HBP program substantially

complete

20% Increase in EUR over two years


ENHANCING OUR BASE PRODUCTION IMPROVED RECOVERY FROM OUR ASSETS

• Abundant opportunities within Chesapeake

˃ 4,600 under-stimulated legacy wells

• Re-stimulating the Barnett

˃ Early field completions were small

˃ 1,100+ potential re-frac opportunities

• Enhancing the Haynesville

˃ New drills enhance existing producers

˃ Evaluating re-frac options vs. stimulation from development program


HAYNESVILLE NEW WELL DESIGNS ARE EXPANDING THE PLAY

• Increased lateral lengths and enhanced stimulations have expanded the core of the play

˃ EUR expected to increase 200%

˃ Expected 42% reduction in cost per lateral foot

˃ 50% improvement in capital efficiency expected

• Enhanced stimulation design makes lower quality reservoirs economic and increases our available location count

7

9.3

14

4,500

5,000

7,500

0

2

4

6

8

10

12

14

16

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Traditional Well Modern Well Modern ExtendedLateral

EUR (BCF)

Lateral Length (ft)

1,900

1,500

1,100

10

15

18

5

7

9

11

13

15

17

19

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Traditional Well Modern Well Modern ExtendedLateral

Well Cost / Lateral Ft

IP Rate (MMCFPD)

$8.5 mm $8.3 mm

$7.5 mm


HAYNESVILLE NEW STIMULATION TECHNIQUES DRIVE PERFORMANCE

• Enhanced stimulations have expanded the core of the play

˃ Extending production peaks

˃ Greater than a 25% increase in EUR

˃ Expands developable area by 90,000 net acres to a total of 184,000 net acres


BOSSIER SHALE CREATING VALUE IN ALL PRODUCTIVE FORMATIONS

• Capital efficiencies and enhanced completion techniques open play for development

• Low existing well count allows development with longer laterals

• 200 – 400 incremental development wells

• Competitive with traditional Haynesville

171

285

422

Area 1 Areas 1 & 2 Areas 1 - 3

Cumulative Well Count

4,500 ft7,500 ft10,000 ft

0

2

4

6

8

10

12

14

16

0 30 60 90

Avera

ge D

aily

Pro

duction R

ate

(m

mcf/d)

Days

Enhanced Bossier Completion Tests

Modern Well Rate Traditional Well Rate

BEDSOLE 1-10-13 H-2 ALT

IP: 14.2 MMcf/day

4,700’ Lateral, $7.7MM

CHK MIN 28-10-13 2H ALT

IP: 14.6 MMcf/day

4,450’Lateral, $6.9MM


0

200

400

600

800

1,000

1,200

1,400

0

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1,200

1,400

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Cum

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roductio

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mboe)

Avera

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oe/d

End of YEAR

2014 Program Daily Avg. Rate2015 Program Daily Avg. Rate2014 Program Cumulative Production2015 Program Cumulative Production

UTICA ENHANCED COMPLETIONS PROGRESS

• 20% EUR improvement driven by

enhanced completions

˃ Longer lateral lengths

˃ Increased stages per well

˃ Tailored cluster spacing

(1) Type curve represents core wet development area

4,900 ft. 5,150 ft. 6,200 ft. 7,900 ft.

10

17

29

41

2012 2013 2014 2015E

Lateral Length per Well

Stages per Well

Completion Performance

>25% Expected increase in lateral lengths vs. 2014

Eight stages per day Current average stages per day per crew; 12 stages max by single crew

Type Curve (1)

1,595 mboe gross EUR type curve

1,265 boe/d first month avg


UTICA INDUSTRY-LEADING PERFORMANCE

0

200

400

600

800

1,000

1,200

0

5

10

15

20

25

30

CHK COMP A COMP B COMP C COMP D

Ft / D

ay

Drill

Days

Drill Days

Penetration Rate

Drilling Performance

$0

$2

$4

$6

$8

$10

$12

CHK COMP B COMP C COMP D COMP A

Gro

ss C

apex /

Well,

$m

m

Average Well Cost

Most efficient driller by 40% Based on IHS Supply Analytics – November 2014 Report


POWDER RIVER NIOBRARA COMPLETION PERFORMANCE

• 20% EUR improvement driven by

enhanced completions

˃ Averaged lateral length of 5,425’ in 2014

(+7% vs. 2013)

˃ Averaged 20 frac stages in 2014

(+33% vs. 2013)

• Testing stacked laterals

0

100

200

300

400

500

600

700

0

200

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1,400

0 1 2 3

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oe/d

End of Year

2014 Program Daily Avg. Rate

2015 Program Daily Avg. Rate

2014 Program Cumulative Production

2015 Program Cumulative Production

Niobrara Type Curve

8,795’ Record lateral length

42 stages Record per well

1,085 mboe gross EUR type curve

1,270 boe/d first month average


CAPTURING MORE FOR LESS NORTHERN DIVISION

Marcellus North: 39% Improvement Utica: 53% Improvement

Powder River: 46% Improvement

Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well


CAPTURING MORE FOR LESS SOUTHERN DIVISION

Haynesville: 67% Improvement Eagle Ford: 38% Improvement

Mississippian Lime: 47% Improvement

Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well


DRILLING AND SERVICES COMMITMENTS

• Commitments roll off through 2015 – CHK has chosen to pay some penalties due to current market conditions and desire to lower overall spending

51

Rigs

45

Rigs

51

Rigs

65

Rigs

71

Rigs

$0

$25

$50

$75

$100

$125

$150

Q1 2015 Q2 2015 Q3 2015 Q4 2015

Tota

l C

om

mitm

ent ($

in m

m)

PTL Commitment Fulfilled

Drill Commitment Fulfilled

Drill Commitment Penalty

1Q’15 2Q’15 3Q’15 4Q’15 E

Note: commitments as of 12/31/2014

E E


CORPORATE INFORMATION

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/

#165167826 N/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

6100 N. Western Avenue

Oklahoma City, OK 73118

WEBSITE: www.chk.com

CHESAPEAKE HEADQUARTERS

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 by phone at (405) 935-8870 or by email at [email protected]

CORPORATE CONTACTS

mailto:[email protected]

UBS Global Oil and Gas Conference Presentation

Investor Relations

Transcript of UBS Global Oil and Gas Conference Presentation