Chesapeake Energy Investor Presentation Feb 2015

1 I INVESTOR PRESENTATION 2/25/2015
INVESTOR PRESENTATION
February 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 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.
FORWARD-LOOKING STATEMENTS

WHERE WE ARE TODAY
CORPORATE PROGRESSION
2013 2014 2015+
TRANSFORMATION
FOUNDATION
E&P LEADERSHIP

OPERATIONAL
> Best safety performance in our history, 35% improvement YOY
> Reduced cumulative reportable spill volume by 40%
> Lowest production and G&A costs per BOE in a decade
> 30 - 60% capital efficiency improvement by play
> Highest production in company history achieved with less than half the operating rigs in 2012
STRATEGIC
> Successful spin-off of Seventy Seven Energy
> $450 million property exchange in oil-rich PRB (RKI)
> Southern Marcellus divestiture – largest transaction in company history
FINANCIAL
> $4.2 billion reduction in total leverage
> New unsecured, undrawn $4 billion credit facility with investment grade-like terms
> Two-notch upgrade from credit rating agencies
2014 ACCOMPLISHMENTS

APPLYING OUR BUSINESS STRATEGIES
FINANCIAL DISCIPLINE
> Balance capital expenditure with cash flow from
operations
> Increase financial and operational flexibility through
value-driven spending and lower business costs
> Achieve investment grade metrics
PROFITABLE AND EFFICIENT GROWTH
FROM CAPTURED RESOURCES
> Develop world-class inventory
> Target top-quartile operating and financial metrics
> Pursue continuous improvement
> Drive value leakage out of our operations
EXPLORATION
> Leverage innovative technology and expertise
> Explore and exploit domestic resources
> Pursue international growth opportunities
BUSINESS DEVELOPMENT
> Target strategic acquisitions
> Enhance and expand the portfolio

2015E OUTLOOK SUMMARY
2015E
Adjusted Production Growth 3 – 5%
Absolute Production:
Liquids – mmbbls 62 – 64
Oil – mmbbls 39 – 40
NGL(1)
– mmbbls 23 – 24
Natural gas - bcf 1,035 – 1,055
Total absolute production – mmboe 235 – 240
Absolute daily rate – mboe 645 – 655
Operating Costs per Boe of Projected Production:
Production expenses, production taxes and G&A(2) $6.40 – $7.10
Capital Expenditures($mm)(3)
$3,500 – $4,000
Capitalized Interest ($mm) $500
Total capital expenditures ($mm) $4,000 – $4,500
(1) Assumes ethane recovery in Utica to fulfill CHK’s pipeline commitments, no ethane recovery in Powder River Basin, and partial ethane recovery in Mid-Continent and Eagle Ford
(2) Excludes stock-based compensation and restructuring and other termination costs
(3) Includes capital expenditures for drilling and completion, acquisition of unproved properties, geological and geophysical costs and other property and plant and equipment

MEASURED GROWTH
Adjusted Production (mboe/d)
586
2013(1)
640
622
2014(1)
2015E
18
2015E Asset Sale
640 –
652
(1) Adjusted to reflect production, net of 2013 and 2014 asset sales
640 – 650
Absolute Production (mboe/d)
670
2013 2014 2015E
706
645 – 655

1Q’15 PRODUCTION
4Q’14 – 1Q’15 Production Walk (mboe/d)
729
4Q’14
Divestitures(1)
Curtailments
(15)
1Q’15E
645 - 655
(57)
(7)
Downtime
(1) Includes Marcellus South and Other
770
December
‘14
Peak
Rate

2014 FINANCIAL RESULTS
PROD. and G&A EXP.
$ 8.1 billion(2)
LIQUIDITY 2014 ASSET SALES TOTAL CAPEX
$ 7.0 billion 14% YOY
$6.7 billion(3)
ADJ. EARNINGS/FDS ADJ. EBITDA
9% YOY
$6.84/boe(1)
$ 4.94 billion$ 1.49
(1) Includes stock-based compensation and production taxes
(2) Includes unrestricted cash and borrowing availability under unsecured revolving credit facility as of 12/31/2014
(3) Includes D&C costs, other explorations and development costs, PP&E, PRB property exchange, sale leasebacks and capitalized interest
Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 32-33

2014 OPERATIONAL RESULTS
(1) Adjusted for asset sales
(2) Oil and NGL collectively referred to as “liquids”
9%YOY
640 mboe/d(1)
LIQUIDS MIX(2)
ADJ. OIL PRODUCTION
29% 7%YOY
110 mbbls/d
ADJ. NGL PRODUCTION PROVED DEVELOPED
of Total
Production
42%YOY
70 mbbls/d
75%
68% in 2013
PROVED RESERVES
2.47Billion BOE to
of Total
Proved
Reserves
ADJUSTED PRODUCTION

• Delivered 2014 adjusted production growth of 9%
> 12% growth if Marcellus South divestiture excluded
• 2.47 billion boe of proved reserves at YE’14
> Proved developed portion increased to 75% of total
• 2015E total Capex of $4.0 - $4.5 billion(1)
> YOY decrease of ~25% (before acquisitions and sale
leasebacks), or ~35% decrease from total capex
> CHK’s 2015 planned rig count lowest since 2004
OPERATIONS UPDATE
Operated Rig Count
(1) Includes capital expenditures for drilling and completion, acquisition of unproved properties, geological and geophysical costs and other PP&E and capitalized interest
(2) Includes Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays
(3) Includes Barnett, Marcellus South (sold Dec’14) and all other producing properties not listed
4Q’14 Daily Avg. Net Production (mboe/d)
% of 2015E D&C Capex by Play
(3)
(2)
(2)
(3)

CAPTURING MORE FOR LESS
NORTHERN DIVISION
Marcellus North: 39% ImprovementUtica: 53% Improvement
Powder River Basin: 46% Improvement
(1) (1)
(1)
Note: Capex / EUR is defined as net drilling and completion (D&C) costs per well divided by net estimated ultimate reserves booked per well
(1) 2014 estimated D&C costs per well and net reserves booked per well are as of 12/31/2014

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
(1) 2014 estimated D&C costs per well and net reserves booked per well are as of 12/31/2014
(1) (1)
(1)

• Largest producer, leasehold owner and most
active driller
> Operate >55% of wells in the play
• 4Q’14 avg. net production of 100 mboe/d
> Up 17% sequentially
> 180 mboe/d gross operated
• Plan to avg. 3 - 5 rigs, four frac crews in ’15
> ~45% HBP drilling, ~80% pad drilling
• ~165 wells WOC/WOP at YE’14, anticipate
>20% reduction in 2015
• 3 - 5 oil window completions planned in 2015
UTICA
ASSET OVERVIEW
CHK/TOT JV Outline
CHK Operated Rigs
CHK Leasehold
Oil Window
Wet Gas Window
Dry Gas Window
Production mix
>1 million net acres
61% avg WI

UTICA
CONTINUOUS IMPROVEMENT
(1) (1)
(1) As measured from Jan.-Oct.
6,000

• 4Q’14 avg net production of ~106 mboe/d
• Plan to avg. 12 - 14 rigs, four frac crews in ’15
> 95% pad drilling
• 123 wells brought online in 4Q’14 had an avg.
peak rate of 850 boe/d
• ~160 wells WOC/WOP at YE’14
EAGLE FORD
ASSET OVERVIEW
CHK Operated Rigs
CHK Leasehold
Oil Window
Wet Gas Window
Dry Gas Window
Production mix
449,000 net acres
61% avg WI

EAGLE FORD
(1)
(1) (1)
5,900

• Largest producer, leasehold owner and
most active driller
• 4Q’14 avg. net production of 592 mmcfe/d
> 910 mmcfe/d gross operated
• Plan to avg. 7 - 8 rigs, 1 frac crew in ’15
> 100% pad drilling
• 18 wells brought online in 4Q’14 had an
avg. peak rate of 13.4 mmcfe/d
HAYNESVILLE
ASSET OVERVIEW
CHK Operated Rigs
CHK Leasehold
Production mix
387,000 net acres
71% avg WI

HAYNESVILLE
(1)
(1)

• Closed transaction with RKI in August ’14
> Exchanged nonoperated northern acreage and
$450 mm cash for RKI’s southern acreage
• 4Q’14 avg net production of ~18 mboe/d
• Plan to avg. 3 - 4 rigs, one frac crew in ’15
> 100% pad drilling
• 50:50 development plan of Niobrara / Sussex
wells in 2015
• Stacked formation tests in 2015:
> 1 Sussex Northern boundary test
> 1 in Teapot
> 1 in Shannon
> 1 in Parkman
POWDER RIVER BASIN
ASSET OVERVIEW
CHK Operated Rigs
CHK Leasehold
Production mix
388,000 net acres
79% avg WI

POWDER RIVER BASIN
(1) (1)

• 4Q’14 avg. net production of 28 mboe/d
• Plan to avg. 7 - 8 rigs, two frac crews in ’15
> 85% pad drilling
• 42 wells brought online in 4Q’14 had an
avg. peak rate of 730 boe/d
MISSISSIPPIAN LIME
ASSET OVERVIEW
CHK Operated Rigs
CHK Leasehold
Production mix
164,000 net acres
44% avg WI

MISSISSIPPIAN LIME
(1) (1)
(1)

• 4Q’14 avg net production of ~817 mmcfe/d
> 2.07 bcfe/d gross operated
• Plan to avg. 1-2 rigs in 2015
> 100% pad drilling
• 25 wells brought online in 4Q’14 had an avg.
peak rate of 15.2 mmcfe/d
• Upper Marcellus test wells planned in 2015
• Projecting to hold total production relatively flat
in 2015 with 70% less capex
MARCELLUS
ASSET OVERVIEW
CHK Operated Rigs
CHK Leasehold
Production mix
230,000+ net acres
39% avg WI
Franclaire 8H
30.6 mmcf/d
Franclaire 7H
30.2 mmcf/d
Franclaire 9H
22.4 mmcf/d

MARCELLUS
(1) (1)
5,900

APPENDIX

REDUCING LEVERAGE
10%
($mm) 2012 2014
Term Loan $2,000 --
Long-Term Bonds $10,666 $11,766
Credit Facility $418 --
GAAP Debt $13,084 $11,766
VPPs $3,187 $1,720
Operating & Finance Leases $1,255 --
Subsidiary Preferred $2,500 $1,250
Corporate Preferred $1,531 $1,531
Adjusted Leverage $21,558 $16,267
Cash $287 $4,108
Total Adjusted Leverage (net of cash) $21,271 $12,159
25%
43%

UPSIDE POTENTIAL
CHK

2015 HEDGING POSITIONS
43% 43%
Natural Gas Oil
20%
3-Way
Collars
$4.51/$4.29/$3.37
/mcf NYMEX
23%
Swaps
$4.14/mcf
NYMEX
Note: Hedged positions as of 1/31/2015 based on production estimates provided in 2/25/2015 Outlook
32%
Swaps $94.58/bbl NYMEX
$98.94/$90/$80
/bbl NYMEX
11%
3-Way
Collars

• Average transportation rates of
$0.24mcf per day for 2015
• Gulf Coast Market Access
> 440 MMcf/d to the Gulf Coast for 2015
> 732 MMcf/d to the Gulf Coast
beginning in 2016
• Upper Midwest/Canadian Market
Access
> 200 MMcf/d of capacity to Dawn
market in 2017
• Local Market Access
> 96 MMcf/d to local markets
UTICA DOWNSTREAM MARKETING ADVANTAGE
Utica
Gulf
Coast
Dawn

$1,500
2015 2016 2017 2018 2019 2020 2021 2022 2023
$396
$2,245
$1,015
$1,800
$1,100
$1,500
$1,700
2.75%(1) 3.25% 2.5%(1) 2.25%(1) 3mL+3.25%(3) 6.875% 5.375% 4.875% 5.75%
6.5% 7.25% 6.625% 6.125%
6.25%(2)
$500
(1) Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes
(2) Euro-denominated notes with a principal amount based on the exchange rate of $1.2098 to €1.00 at 12/31/2014
(3) All-in yield composed of 3.25% spread and 3mL
Convertibles(1)
Other Senior Notes
Sr. Notes: $11.8 billion
12/31/2014 WACD – 5.1%
Avg. Maturity: 4.9 years
SENIOR NOTE MATURITY PROFILE

($ in mm)
Twelve Months Ended: 12/31/2014 12/31/2013
Net income available to common stockholders $1,273 $474
Adjustments, net of tax:
Unrealized gains on derivatives (941) (100)
Restructuring and other termination costs 4 154
Impairments of fixed assets and other 57 341
Net gains on sales of fixed assets (128) (187)
Impairments of investments 3 6
Net (gain) loss on sales of investments (43) 5
Losses on purchases of debt and extinguishment of other financing 126 120
Losses on investments - 84
Provision for legal contingencies 150 -
Other 9 (1)
Redemption of preferred shares of a subsidiary(1) 447 69
Adjusted net income available to common stockholders(2) $957 $965
Preferred stock dividends 171 171
Earnings allocated to participating securities 26 10
Total adjusted net income attributable to CHK $1,154 $1,146
Weighted average fully diluted shares outstanding(3) 776 765
Adjusted earnings per share assuming dilution(2) $1.49 $1.50
(1) All adjustments to net income available to common stockholders reflected net of tax other than the redemption of preferred shares of a subsidiary.
(2) 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 accounting principles generally accepted in the United States (GAAP) because:
(i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil 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 amounts cannot be reasonably estimated.
Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Management believes that “adjusted net income attributable to common
stockholders” represents a useful corollary to net income attributable to common stockholders because it provides useful information regarding our ongoing operations and is widely used by investors,
analysts and rating agencies in the valuation, rating and investment recommendations of companies.
(3) In millions. 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)
Twelve Months Ended: 12/31/2014 12/31/2013
Cash provided by operating activities $4,634 $4,614
Changes in assets and liabilities 392 344
Operating cash flow(1)
$5,026 $4,958
Net income $2,056 $894
Interest expense 89 227
Income tax expense 1,144 548
Depreciation and amortization of other assets 232 314
Oil, natural gas and NGL depreciation, depletion and amortization 2,683 2,589
EBITDA(2)
$6,204 $4,572
Adjustments:
Unrealized gains on oil, natural gas and NGL derivatives (1,394) (228)
Restructuring and other termination costs 7 248
Impairments of fixed assets and other 88 550
Net gains on sales of fixed assets (199) (302)
Losses on investments 5 146
Net (gain) loss on sales of investments (67) 7
Losses on purchases of debt and extinguishment of other financing 197 193
Provision for legal contingencies 234 _
Net income attributable to noncontrolling interests (139) (170)
Other 9 --
Adjusted EBITDA(3) $4,945 $5,016
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 a natural gas and oil company's ability to generate cash which 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 natural gas and oil 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 (loss) 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 net income because:
(i) Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies.
(ii) Adjusted ebitda is more comparable to 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.

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 ir@chk.com
CORPORATE CONTACTS

Chesapeake Energy Investor Presentation Feb 2015

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to Chesapeake Energy Investor Presentation Feb 2015

Similar to Chesapeake Energy Investor Presentation Feb 2015 (20)

More from Marcellus Drilling News

More from Marcellus Drilling News (20)

Recently uploaded

Recently uploaded (17)

Chesapeake Energy Investor Presentation Feb 2015