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

2.47 Billion 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% Improvement Utica: 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 > Up 4% sequentially

> 230 mboe/d gross operated

• 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 CONTINUOUS IMPROVEMENT

(1)


(1) (1)

5,900


• Largest producer, leasehold owner and most active driller

• 4Q’14 avg. net production of 592 mmcfe/d > Up 5% sequentially > 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



HAYNESVILLE CONTINUOUS IMPROVEMENT


(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

> Up 29% sequentially > 27 mboe/d gross operated

• Plan to avg. 3 - 4 rigs, one frac crew in ’15 > 100% pad drilling

• ~40 wells WOC/WOP at YE’14 • 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


Production mix



POWDER RIVER BASIN CONTINUOUS IMPROVEMENT

(1) (1)



• 4Q’14 avg. net production of 28 mboe/d > Up 4% sequentially > 72 mboe/d gross operated

• 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


Production mix



MISSISSIPPIAN LIME CONTINUOUS IMPROVEMENT


(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

• ~115 wells WOC/WOP at YE’14 • 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


Production mix

230,000+ net acres

39% avg WI

Franclaire 8H 30.6 mmcf/d




MARCELLUS CONTINUOUS IMPROVEMENT


(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 [email protected]

CORPORATE CONTACTS

mailto:[email protected]

Chesapeake Energy Investor Presentation Feb 2015

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Transcript of Chesapeake Energy Investor Presentation Feb 2015