1. business and industrial
2. energy
3. natural gas

Investor Presentation
November 5, 2014
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, planned 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. Further, pending divestiture transactions are subject to closing conditions and may not be completed in the
time frame anticipated or at all. In particular, we caution you that our October 2014 purchase and sale agreement with Southwestern Energy Company, in
which we agreed to sell certain assets in the Marcellus Shale and Utica Shale for approximately $5.375 billion, is subject to closing conditions, including
third-party consents and waiver of participation rights. These closing conditions may not be completed in the time frame anticipated or at all. 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 2013 annual
report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 27, 2014. These risk factors include the volatility of natural gas,
oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially
resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales, to fund reserve
replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil 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; hedging activities resulting in lower prices realized on natural
gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating
risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives
related to hydraulic fracturing, air emissions and endangered species; uncertainties regarding legal claims and governmental proceedings, including royalty
claims, and the adequacy of our provision for legal contingencies; a deterioration in general economic, business or industry conditions having a material
adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity
constraints and various transportation interruptions that could adversely affect our revenues and cash flow; adverse developments and losses in connection
with pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and an interruption at our headquarters that
adversely affects our business.
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 dependent upon many assumptions, including estimates
of production decline rates from existing wells and the outcome of future drilling activity. 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 release, except as required by applicable law.
2 I INVESTOR PRESENTATION 11/5/2014
WHERE WE ARE TODAY
CORPORATE PROGRESSION
2013
2014
2015 +
TRANSFORMATION
FOUNDATION
E&P LEADERSHIP
3 I INVESTOR PRESENTATION 11/5/2014
APPLYING OUR BUSINESS STRATEGIES
• Balance capital expenditures with
cash flow from operations
• Divest noncore assets and
noncore affiliates
• Develop world-class inventory
• Target top-quartile operating and
financial metrics
• Pursue continuous improvement
• Reduce financial and operational
risk and complexity
• Drive value leakage out of
operations
• Achieve investment grade metrics
4 I INVESTOR PRESENTATION 11/5/2014
3Q’14 OPERATIONAL AND FINANCIAL RESULTS
TOTAL ADJ. PROD.
11% YOY
(1)
726 mboe/d
ADJ. EARNINGS/FDS
(1)
(2)
(3)
LIQUIDS MIX
to
29%
ADJ. OIL PROD.
5% Q/Q
of Total
Production(2)
28% in 2Q’14
ADJ. EBITDA
12% YOY
7% YOY
$0.38(3)
$1.24 billion(3)
(1)
118.9 mbbls/d
CAPEX
8% YOY
$1.35 billion
Adjusted for asset sales
Oil and NGL collectively referred to as “liquids”
Adjusted earnings per fully diluted share and adjusted EBITDA are non-GAAP financial measures. A reconciliation of non-GAAP financial measures to comparable
GAAP financial measures appears on pages 24 – 25
5 I INVESTOR PRESENTATION 11/5/2014
CAPITAL DISCIPLINE
(1)
$ in billions
$14.2
$7.6
~$5.7
60%
36%
Decrease in
Capital Investment
Increase in Operating
Cash Flow
(2)
(1) Operating Cash Flow before changes in assets and liabilities
(2) 2014 based on midpoint of company Outlook issued on 11/5/2014; capex includes capitalized interest, but excludes the exchange of properties with RKI Exploration and
Production, LLC for ~$450 million in August 2014
6 I INVESTOR PRESENTATION 11/5/2014
mmboe
Inventory Count
GROWING PRODUCTION WHILE MANAGING
INVENTORY
7 I INVESTOR PRESENTATION 11/5/2014
OPERATIONS UPDATE
• Operating cash flow(1) for first nine months of
2014 of approximately $4.2 billion, compared to
capital expenditures of $3.5 billion(2)
3Q’14 Daily Avg. Net Production (mboe/d)
• Adjusted production(3) for first nine months was
12% higher than year-ago levels
(5)
• Achieved year-end estimated exit rate of 730
mboe/d in September, 2014
2014E % of E&P Capex by Play(2)(4)
2014E Avg. Operated Rig Count
<5%
<5%
17-20
(5)
~
~ ~
42 - 49 Liquids Focused Rigs
13 - 16 Natural Gas Focused Rigs
55 - 65 Total Operated Rigs
~
5-6
~
~
~
(1)
(2)
(3)
(4)
(5)
~
Operating Cash Flow before changes in assets and liabilities
Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the august 2014 exchange of properties with RKI Exploration and Production, LLC.
Adjusted for asset sales in 2013 and 2014
Net of Utica and PRB drilling carries; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A; excludes capitalized interest
Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and Other Anadarko plays
8 I INVESTOR PRESENTATION 11/5/2014
EAGLE FORD
ASSET OVERVIEW
•
3Q’14 avg. net production of ~102 mboe/d
>
•
Up 12% sequentially
Averaged 21 operated rigs (3 of which were
spudder rigs) and connected 89 gross wells in
3Q’14
•
449,000 net acres
•
61% avg WI, 46% avg NRI
•
~40% of 2014 estimated E&P capex
•
Avg. completed well cost of ~$6.0 million(2)
(1)
(2)
CHK Operated Rigs
CHK Leasehold
Oil Window
Wet Gas Window
Dry Gas Window
Production mix(1)
3Q’14 avg. daily production
As measured from Jan-July
9 I INVESTOR PRESENTATION 11/5/2014
UTICA
ASSET OVERVIEW
•
3Q’14 avg. net production of ~86 mboe/d
>
•
Up 27% sequentially
Averaged 7 operated rigs and connected 77
gross wells in 3Q’14
•
•
(1)
(2)
(3)
Over 1 million net acres
>
250,000 net acres in wet gas window
>
300,000 net acres in oil
>
540,000 net acres in dry gas(1)
>
71% avg. WI, 57% avg. NRI
CHK/TOT JV Outline
CHK Operated Rigs
CHK Leasehold
Oil Window
Wet Gas Window
Dry Gas Window
Production mix(2)
Avg. completed well cost of ~$6.5 million(3)
Utica dry gas acreage includes 165,000+ acres that overlap in Southern Marcellus, the proposed sale of which was announced in
October 2014
3Q’14 daily average net production
As measured from Jan-July
10 I INVESTOR PRESENTATION 11/5/2014
POWDER RIVER BASIN
NIOBRARA ASSET OVERVIEW
•
Net production of ~14 mboe/d(1)
•
Three operated rigs in 3Q’14 and connected
17 gross wells in 3Q’14
•
388,000+ net acres
•
79% avg. WI
•
Buckinghorse Plant (4Q'14) expected to add
120 mmcf/d processing capacity
•
CHK Operated Rigs
CHK Leasehold
Avg. completed well cost of ~$9.2 million
Production mix(1)
(1)
(2)
3Q’14 daily average net production
As measured from Jan-July
11 I INVESTOR PRESENTATION 11/5/2014
EXECUTING OUR PLAN
(1)
(2)
Production growth(1)
9 – 12%
Cash flow
$5,250 – $5,450 MM
Capital
$5,000 – $5,400 MM(2)
Cash costs
LOE, G&A and interest expense
Leverage
Reduce adjusted leverage by 30%
YE 2014
Growth range based on 2013 production of 604mboe/day adjusted for asset sales in 2013 and 2014
Excludes capitalized interest and approximately $450 million of cash paid by the company in conjunction with the August 2014 exchange of properties with
RKI Exploration and Production, LLC.
12 I INVESTOR PRESENTATION 11/5/2014
APPENDIX
13 I INVESTOR PRESENTATION 11/5/2014
TRANSFORMING OUR BUSINESS
• Organizational structure
• Decision rights
• Focus on capital efficiency
• Cash cost reduction
• Portfolio management and capital
allocation process
• Corporate budget process and plan
• Performance measurement and
compensation program
14 I INVESTOR PRESENTATION 11/5/2014
FOUNDATIONAL ELEMENTS
FOR VALUE CREATION
• Growing production while de-levering
• Industry-leading capital efficiency
• Differential future growth
CHK
15 I INVESTOR PRESENTATION 11/5/2014
NORTHERN MARCELLUS
ASSET OVERVIEW
•
3Q’14 avg. net production of ~882 mmcfe/d
>
•
Up 1% sequentially
Averaged 3 operated rigs and connected 23
gross wells in 3Q’14
•
230,000+ net acres(1)
•
39% avg. WI, 34% avg. NRI
•
Avg. completed well cost of ~$7.0 million(3)
CHK Operated Rigs
CHK Leasehold
Production mix(2)
(1)
(2)
(3)
Excludes acreage off main development fairway
3Q’14 daily average net production
As measured from Jan-July
16 I INVESTOR PRESENTATION 11/5/2014
MID-CONTINENT
ASSET OVERVIEW
•
3Q’14 avg. net production of ~96 mboe/d
•
Averaged 18 operated rigs and connected
63 gross wells in 3Q’14
•
249,000 net acres actively being developed
in aggregate
˃ Mississippian Lime
˃
164,000 net acres
˃
44% avg WI, 36% avg NRI
Miss. Lime
Granite Washes
CHK Leasehold
CHK Operated Rigs
˃ Granite Wash plays(1)
˃
85,000 net acres
˃
83% avg WI, 67% avg NRI
Production mix(2)
˃ ~1.9 mm net acres of legacy leasehold
•
~20% of 2014 estimated E&P capex
•
Avg. completed well cost of $3.1 million in
the Mississippian Lime(3)
(1)
(2)
(3)
Granite Wash plays include Colony Granite Wash, TX Panhandle Granite Wash and Missourian Granite Wash
3Q’14 daily avg. net production
As measured from Jan-July
17 I INVESTOR PRESENTATION 11/5/2014
HAYNESVILLE
ASSET OVERVIEW
•
3Q’14 avg. net production of ~562 mmcfe/d
>
•
Up 11% sequentially
Averaged 9 operated rigs and connected 14
gross wells in 3Q’14
•
387,000 net acres
•
71% avg WI, 57% avg NRI
•
Avg. completed well cost of ~$8.2 million(2)
CHK Operated Rigs
CHK Leasehold
Production mix(1)
(1)
(2)
3Q’14 daily avg. net production
As measured from Jan-July
18 I INVESTOR PRESENTATION 11/5/2014
BARNETT SHALE
ASSET OVERVIEW
•
3Q’14 avg. net production of ~562 mmcfe/d
•
1 - 2 operated rigs in 2014
•
215,000 net acres
•
68% avg WI, 52% avg NRI
•
<5% of 2014 estimated E&P capex
•
Field maturity now entering period of low
base decline rate
•
Avg. completed well cost of ~$2.9
CHK Operated Rigs
CHK Leasehold
million(2)
Production mix(1)
(1)
(2)
3Q’14 daily average net production
As measured from Jan-July
19 I INVESTOR PRESENTATION 11/5/2014
CURRENT HEDGE POSITION
Natural Gas
Oil
72%
64%
42%
Swaps
$4.50-$5.24/mcf
NYMEX
$4.09/mcf
NYMEX
$94.22/bbl
NYMEX
26%
Three-Way
Collars
$4.11 - $4.37/mcf
NYMEX
Natural Gas Hedges
Crude Oil Hedges
Q4 2014
Total 2015
Volume (bcf)
194
319
Price ($/mcf)
$4.12
$4.31
Volume (mmbls)
7,197
16,837
Price ($/bbl)
$94.22
$93.39
Note: Hedged positions as of 11/1/2014 based on production estimates provided in 11/5/2014 Outlook; 26% of 2014 gas production is hedged under collar
arrangements with upside to average NYMEX price of $4.37/mcf and exposure below average NYMEX price of $3.49/mcf
20 I INVESTOR PRESENTATION 11/5/2014
UTICA DOWNSTREAM MARKETING ADVANTAGE
•
Average transportation rates of $0.22
per mcf per day for balance of 2014
Dawn
and $0.24 per mcf per day for 2015
•
•
Gulf Coast Market Access
>
440 MMcfd to the Gulf Coast for 2015
>
732 MMcfd to the Gulf Coast
beginning in 2016
Utica
Upper Midwest/Canadian Market
Access
>
•
200 MMcfd of capacity to Dawn
market in 2017
Local Market Access
>
Gulf
Coast
96 MMcfd to local markets
21 I INVESTOR PRESENTATION 11/5/2014
REDUCING LEVERAGE
($mm)
Term Loan
2012
2014E(1)(2)
$2,000
--
Long-Term Bonds
$10,666
$11,821
$418
--
$13,084
$11,821
VPPs
$3,187
$1,720
Operating & Finance Leases
$1,255
--
Subsidiary Preferred
$2,500
--
Corporate Preferred
$1,531
$1,531
$21,558
$15,061
Credit Facility
GAAP Debt
Total Adjusted Leverage
~$6.5B
Reduction in Leverage
During the Past 2 Years
(1)
(2)
Assumes takeout of Cleveland-Tonkawa, sale of South and East Texas conventional assets (VPP 6) in 2H 2014
Excludes approximately $5.4 billion in potential proceeds from the proposed Southern Marcellus asset sale, subject to close in December 2014
22 I INVESTOR PRESENTATION 11/5/2014
~10%
~30%
SENIOR NOTE PROFILE
Convertibles
Other Senior Notes
Sr. Notes: $11.8 billion
9/30/2014 WACD – 5.0%
Avg. Maturity: 5.2 years
$2,263
$1,800
$1,700
$1,500
$1,500
$1,100
$1,015
$396
$500
$0
2014
2015
2.75%(1)
(1)
(2)
(3)
2016
3.25%
2017
2.5%(1)
6.5%
6.25%(2)
2018
2019
2.25%(1)
7.25%
3mL+3.25%(3)
2020
6.875%
6.625%
2021
2022
2023
5.375%
6.125%
4.875%
5.75%
Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes
Euro-denominated notes with a principal amount based on the exchange rate of $1.2631 to €1.00 at 9/30/2014
All-in yield composed of 3.25% spread and 3mL
23 I INVESTOR PRESENTATION 11/5/2014
RECONCILIATION OF ADJUSTED EARNINGS PER
SHARE
($ in mm, except per share data)
Three Months Ended:
9/30/2014
9/30/2013
$169
$156
(384)
(9)
9
(54)
62
11
447
118
39
55
(82)
(2)
(2)
-
$251
$282
43
3
43
3
Total adjusted net income attributable to CHK
$297
$328
Weighted average fully diluted shares outstanding(3)
776
765
$0.38
$0.43
Net income available to common stockholders
Adjustments, net of tax:
Unrealized losses on derivatives
Restructuring and other termination costs
Impairments of fixed assets and other
Net gains on sales of fixed assets
Net gains on sales of investments
Provision for legal contingencies
Other
Redemption of preferred shares of a subsidiary(1)
Adjusted net income available to common stockholders(2)
Preferred stock dividends
Earnings allocated to participating securities
Adjusted earnings per share assuming dilution(2)
(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 amount 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.
In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP
(3)
24 I INVESTOR PRESENTATION 11/5/2014
RECONCILIATION OF ADJUSTED EBITDA
($ in mm)
Three Months Ended:
9/30/2014
9/30/2013
$1,184
$1,381
$1,293
$692
$1,412
$240
EBITDA(2)
Adjustments:
$1,871
$1,158
(622)
(14)
15
(86)
-(30)
100
2
191
63
89
(132)
(3)
(38)
-(3)
Adjusted EBITDA(3)
$1,236
$1,325
Cash provided by operating activities
Changes in assets and liabilities
Operating cash flow
Net income
(1)
Interest expense
Income tax expense
Depreciation and amortization of other assets
Natural gas, oil and NGL depreciation, depletion and amortization
Unrealized losses on natural gas, oil and NGL derivatives
Restructuring and other termination costs
Impairments of fixed assets and other
Net gains on sales of fixed assets
Net gains on sales of investments
Net income attributable to noncontrolling interests
Provision for legal contingencies
Other
109
17
437
37
688
31
40
147
79
652
(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.
25 I INVESTOR PRESENTATION 11/5/2014
CORPORATE INFORMATION
CHESAPEAKE HEADQUARTERS
6100 N. Western Avenue
Oklahoma City, OK 73118
WEBSITE: www.chk.com
CORPORATE CONTACTS
BRAD SYLVESTER, CFA
Vice President —
Investor Relations and Communications
DOMENIC J. DELL'OSSO, JR.
Executive Vice President and
Chief Financial Officer
Investor Relations department can be
reached by phone at (405) 935-8870
or by email at [email protected]
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
#165167834/
#165167826
#U16450204/
#165167776/
#165167768
#U16450113/
#165167784/
#165167750
#165167107
CHK PrD
5.0% Cumulative Convertible Preferred Stock (Series 2005B)
5.75% Cumulative Convertible Preferred Stock
5.75% Cumulative Convertible Preferred Stock (Series A)
Chesapeake Common Stock
26 I INVESTOR PRESENTATION 11/5/2014
N/A
N/A
N/A
CHK