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INVESTOR PRESENTATION LAST UPDATED AUGUST 6, 2014
2 I INVESTOR PRESENTATION – AUGUST 6, 2014
• 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, estimated future capital expenditures, estimates of recoverable resources, projected rates of return and expected efficiency gains, as well as projected cash flow, 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 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; 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.
• The transaction with RKI is subject to closing conditions, including third-party consents, and may not be completed in the time frame anticipated or at all. Chesapeake’s interest in the properties acquired in the RKI exchange will be reduced if applicable participation rights are exercised and other conditions, including payment to Chesapeake of consideration for such participation, are fulfilled.
• 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.
FORWARD-LOOKING STATEMENTS
3 I INVESTOR PRESENTATION – AUGUST 6, 2014
(1) 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 39 – 40
(2) G&A includes expenses associated with share-based compensation
(3) Includes unrestricted cash and borrowing availability under revolving credit facility as of 6/30/2014
(4) As of 6/30/2014
PROD. and G&A EXP.
$5.4 billion(3)
LIQUIDITY 1H’14 ASSET SALES TOTAL CAPEX
$1.2 billion(4)
27% YOY
$1.3 billion
ADJ. EARNINGS/FDS
29% YOY
$0.36(1)
ADJ. EBITDA
10% YOY
$1.3 billion(1)
8% YOY
$5.89/boe(2)
2Q’14 FINANCIAL RESULTS
4 I INVESTOR PRESENTATION – AUGUST 6, 2014
2Q’14 OPERATIONAL RESULTS
13% YOY(1)
695 mboe/d
TOTAL ADJ. PROD. LIQUIDS MIX ADJ. OIL PROD.
(1) Adjusted for asset sales
(2) Oil and NGL collectively referred to as “liquids”
28% 25% in 2Q’13
12% YOY(1)
113.4 mbbls/d
ADJ. NGL PROD.
of Total Production(2)
72% YOY(1)
84.3 mbbls/d
ADJ. GAS PROD.
7% YOY(1)
3.0 bcf/d
to
5 I INVESTOR PRESENTATION – AUGUST 6, 2014
• Cash and equivalents increased ~$460 mm to ~$1.5 B at 6/30/14
• Long-term debt, net of cash and discounts decreased $1.9 B to ~$10.1 B, or ~15%
sequentially
2Q’14 LEVERAGE REDUCTION
(1) Net of unrestricted cash and discounts
($1,270)
$1,455
($365)
($1,135)
($310)
($255)
$10,085 $ in
mm
(1) (1)
$11,965
6 I INVESTOR PRESENTATION – AUGUST 6, 2014
• CHK 6/30/14 pro forma unrestricted cash position, including completed and pending
transactions, exceeds $450 mm
RKI ACREAGE SWAP AND UTICA REPURCHASE
FUNDED WITH CASH AND ASSET SALE PROCEEDS
$1,462
($1,260)
($450)
$295
$250
Pro forma cash
balance >$450 mm
$155
$ in
mm
(1)
(1) Includes noncore E&P assets in South Central Oklahoma, East Texas and South Texas
7 I INVESTOR PRESENTATION – AUGUST 6, 2014
CAPITAL DISCIPLINE
$14.2
~$5.8 ~$5.8
(1) 2014 based on midpoint of company Outlook issued on 8/6/2014; capex includes capitalized interest; 2015 estimate midpoint provided at Analyst Day
$7.6
(1) (1)
$ in
billio
ns
8 I INVESTOR PRESENTATION – AUGUST 6, 2014
TRANSFORMING OUR BUSINESS
• Portfolio management and capital
allocation process
• Corporate budget process and plan
• Performance measurement and
compensation program
• Organizational structure
• Decision rights
• Focus on capital efficiency
• Cash cost reduction
9 I INVESTOR PRESENTATION – AUGUST 6, 2014
• Balance capital expenditures with
cash flow from operations
• Divest noncore assets and
noncore affiliates
• Reduce financial and operational
risk and complexity
• Achieve investment grade metrics
• Develop world-class inventory
• Target top-quartile operating and
financial metrics
• Pursue continuous improvement
• Drive value leakage out of
operations
APPLYING OUR BUSINESS STRATEGIES
10 I INVESTOR PRESENTATION – AUGUST 6, 2014
FOUNDATIONAL ELEMENTS
FOR VALUE CREATION
CHK
11 I INVESTOR PRESENTATION – AUGUST 6, 2014
NET ASSET VALUE AND UPSIDE POTENTIAL
(1) Based on commodity prices of $4.50/mcf and $90.00/bbl for natural gas and oil, respectively, >20,000 risked drilling locations, net debt, NCI and
other liabilities of $13 billion for a total net asset value of $32 billion.
CHK
$40 NAV/share(1)
12 I INVESTOR PRESENTATION – AUGUST 6, 2014
APPENDIX
13 I INVESTOR PRESENTATION – AUGUST 6, 2014
• ~1.2 bboe of net recoverable resources
• 2Q’14 avg. net production of ~91 mboe/d
> Up 15% YOY, adjusted for asset sales
> More than 101 mboe/d during last week of July
• Averaged 21 operated rigs (2 of which were
spudder rigs) and connected 104 gross wells
in 2Q’14
• ~35% of 2014 estimated E&P capex
• 610 mboe gross EUR per well – 45% ROR(1)
EAGLE FORD
ASSET OVERVIEW
(1) Assumes NYMEX natural gas, oil and NGL prices of $4.00/mcf, $90/bbl and $36/bbl, respectively and ($3.10)/mcf natural gas and ($3.97)/bbl oil for gathering/transportation costs and regional basis differential. Also assumes 115 day spud to TIL cycle time delay. EUR and ROR based on 2014 program
(2) 2Q’14 avg. daily production
CHK Operated Rigs
CHK Leasehold Oil Window Wet Gas Window Dry Gas Window
Production mix(2)
449,000 net acres 61% avg. WI, 46% avg. NRI
14 I INVESTOR PRESENTATION – AUGUST 6, 2014
EAGLE FORD
CONTINUOUS IMPROVEMENT
• Spud to completion ratio of 1:1
• Substantial cycle-time improvements
• Testing new completion designs to lower cost
and not impact performance
• Continuing to upgrade rig fleet
95% Multiwell pad drilling in 2014
20% Targeted decrease in spud-to-spud cycle time from 2013 to 2014E
7% Targeted decrease in avg. well costs 2013 to YE’14 target
15 I INVESTOR PRESENTATION – AUGUST 6, 2014
MID-CONTINENT
ASSET OVERVIEW
• >500 mmboe of net recoverable resources
in Miss Lime
• >350 mmboe of net recoverable resources
in Granite Wash plays(1)
• 2Q’14 avg. net production of ~98 mboe/d
• Averaged 17 operated rigs and connected
52 gross wells in 2Q’14
• ~20% of 2014 estimated E&P capex
• ~1.9 mm net acres of legacy leasehold
Production mix(2)
(1) Granite Wash plays include Colony Granite Wash, TX Panhandle Granite Wash and Missourian Granite Wash (2) 2Q’14 daily avg. net production
Miss. Lime Granite Washes CHK Operated Rigs
91,000 net acres 83% avg. WI, 67% avg. NRI
195,000 net acres 44% avg. WI, 36% avg. NRI
16 I INVESTOR PRESENTATION – AUGUST 6, 2014
HAYNESVILLE
ASSET OVERVIEW
(1) EUR represents 2014 program (2) 2Q’14 daily avg. net production
Avg. Well Costs ($ in mm)
• ~10 tcfe of net recoverable resources
• 2Q’14 avg. net production of ~508 mmcfe/d
> Up 26% YOY, adjusted for asset sales
• Averaged 8 operated rigs and connected 13
gross wells in 2Q’14
• 8.9 bcfe gross EUR per well(1)
387,000 net acres 71% avg. WI, 57% avg. NRI
Production mix(2)
<
CHK Operated Rigs
Industry Rigs
CHK Leasehold
17 I INVESTOR PRESENTATION – AUGUST 6, 2014
HAYNESVILLE
ECONOMICS
Rate of Return(1)
(1) Represents 2014 program. Burdened ROR scenarios assume differentials to NYMEX natural gas prices of ($1.45)/mcf for gathering/transportation costs and regional basis differential. Also assumes 180 day spud to TIL cycle time delay for a three well pad.
• Cost control measures and improving natural gas prices drive stronger returns
• ROR exceeds 100% when considering minimum volume commitment (MVC) and firm
transport (FT) as sunk costs
>100% Unburdened ROR in Haynesville
18 I INVESTOR PRESENTATION – AUGUST 6, 2014
• 4+ bboe of net recoverable resources
• 2Q’14 avg. net production of ~67 mboe/d
> Up 373% YOY and 34% sequentially
• Averaged 8 operated rigs and connected 48
gross wells in 2Q’14
• Over 1 million net acres
• 1,325 mboe gross EUR per well – 45% ROR(1)
UTICA
ASSET OVERVIEW
(1) EUR assumes ethane recovery to meet ATEX commitment. ROR assumes NYMEX natural gas, oil and NGL prices of $4.00/mcf, $90/bbl and $36/bbl, respectively and ($7.00)/bbl oil and ($1.30)/mcf natural gas for gathering/transportation costs and regional basis differentials. Also assumes 185 day avg. spud to TIL cycle time delay. EUR and ROR based on 2014 program
(2) Utica dry gas acreage includes 165,000+ acres that overlap Southern Marcellus (3) 2Q’14 daily average net production
CHK/TOT JV Outline CHK Operated Rigs Industry Rigs CHK Leasehold Oil Window Wet Gas Window Dry Gas Window
Production mix(3) >250,000 net acres in wet gas window
>300,000 net acres in oil >540,000 net acres in dry gas(2)
71% avg. WI, 57% avg. NRI
19 I INVESTOR PRESENTATION – AUGUST 6, 2014
CHK Leasehold Oil Window Wet Gas Window Dry Gas Window
Oil Window Test Area
CORE EXPANSION IN UTICA:
UNLOCKING THE OIL WINDOW
• Leveraging proprietary Reservoir
Technology Center (RTC)
• Optimizing lateral placement
• Modifying fluid chemistry, volumes
and frac geometries
>500 barrels oil Recent oil IPs (old completion design)
>1,000 boe/d Recent full-stream IPs (old completion design)
20 I INVESTOR PRESENTATION – AUGUST 6, 2014
CORE EXPANSION IN UTICA:
DRY GAS OPPORTUNITY
• 2,000+ potential locations
• Expect 10+ bcfe EURs
• 2014 delineation
> Test in Wetzel County, WV
> Completion scheduled for late August
> Added second rig in WV panhandle
5.9 Mmcf/d Q1 ‘12
5.1 Mmcf/d Q2 ‘12
6.9 Mmcf/d Q4 ‘11
14.7 Mmcf/d Q3 ‘11
12.7 Mmcf/d Q3 ‘12
17.7 Mmcf/d Q3 ‘12
8.6 Mmcf/d Q2 ‘12
18.1 Mmcf/d Q2 ‘13
20.5 Mmcf/d Q3 ‘13
5.9 Mmcf/d Q2 ‘12
30.0 Mmcf/d Q1 ‘13
32.5 Mmcf/d Q2 ‘13
22.5 Mmcf/d Q3 ‘12
Note: Chesapeake peak rates based on old frac design during initial acreage capture
$4 - $7 billion Implied value based on recent transactions
>330,000 acres Net, dry gas acres in Jefferson County, OH and W.V.
6.1 Mmcf/d
7.1 Mmcf/d
6.7 Mmcf/d
5.9 Mmcf/d
5.1 Mmcf/d
6.9 Mmcf/d
14.7 Mmcf/d
12.7 Mmcf/d
17.7 Mmcf/d
8.6 Mmcf/d
18.1 Mmcf/d
20.5 Mmcf/d
5.9 Mmcf/d
30.0 Mmcf/d
32.5 Mmcf/d
22.5 Mmcf/d
CHK Leasehold Oil Window Wet Gas Window Dry Gas Window CHK rates Industry peer rates
21 I INVESTOR PRESENTATION – AUGUST 6, 2014
$6.7 mm/well
$11.8 mm/well
$7.4 mm/well
MOST EFFICIENT OPERATOR IN UTICA
Drill Days (Spud to TD)
$M
/ L
ate
ral F
t
Avg. Capex per Lateral Ft.
Days
Rate of Return %
RO
R %
Note: non-operated data based on 49 wells where CHK has a working interest. Includes Gulfport, Hess, AEP and Eclipse. Wells with insufficient production history excluded from ROR comparison.
CHK Operated Non-Operated CHK Leasehold Oil Window Wet Gas Window Dry Gas Window
22 I INVESTOR PRESENTATION – AUGUST 6, 2014
2.2 miles Record for longest useable lateral drilled by CHK (12,106’ in 20 days )
• Focused on continuous improvement in 2014
> Avg. lateral length >6,000 ft. and 22 frac stages
> More than 15% increase in avg. lateral length YOY
> More than 50% increase in avg. frac stages YOY
UTICA
CONTINUOUS IMPROVEMENT
80% ROR on incremental $1.4 mm investment in completion optimization
Spud to Spud Cycle Times (days)
E
$1.4 mm in
reinvested
capital
Avg. Well Cost ($ in mm)
23 I INVESTOR PRESENTATION – AUGUST 6, 2014
0
20
40
60
80
100
120
1Q'12 2Q'12 3Q'12 4Q'12 1Q'13 2Q'13 3Q'13 4Q'13 1Q'14 2Q'14E 3Q'14E 4Q'14E
Ne
t m
bo
e/d
CASH FLOW GROWTH IN UTICA
>400% YOY production growth (2012 to 2013)
>300% YOY production growth (2013 to 2014E)
30 - 60% YOY production growth (2014E to 2015E)
2Q’14 Avg. Production 67,000 boe/d net
Kensington III (June’14) +200 mmcf/d gross capacity
Cardinal Expansion (4Q’14) +150 mmcf/d gross capacity
Key 2014 Milestones
Natural gas
Oil
NGL
24 I INVESTOR PRESENTATION – AUGUST 6, 2014
• ~9 tcfe of net recoverable resources
• 230,000+ net acres(1)
• 39% avg. WI, 34% avg. NRI
• 2Q’14 avg. net production of ~878 mmcfe/d
> Up 12% YOY
• Averaged 6 operated rigs and connected 21
gross wells in 2Q’14
• 5 - 7 operated rigs in 2014
• 10 bcfe gross EUR per well – 85% ROR(3)
NORTHERN MARCELLUS
ASSET OVERVIEW
(1) Excludes acreage off main development fairway (2) 2Q’14 daily average net production (3) Assumes NYMEX natural gas prices of $4.00/mcf and ($1.35)/mcf for gathering/transportation costs and regional basis differentials. Also assumes 120 day avg. spud to TIL cycle time delay. EUR and ROR based on 2014 program
CHK Operated Rigs Industry Rigs CHK Leasehold
Production mix(2)
25 I INVESTOR PRESENTATION – AUGUST 6, 2014
NORTHERN MARCELLUS
DRIVING VALUE
Value Creation, $M
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0 30 60 90 120 150 180 210 240 270
Gas (
mcf/
d)
Days On
Standard Completion Design
Gross Daily Production Rates
$1 million 2014 savings reinvested into completions optimization
55% ROR on reinvested capital
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0 30 60 90 120 150 180 210 240 270
Gas (
mcf/
d)
Days On
Standard Completion Design Enhanced Completion Design
Gross Daily Production Rates
26 I INVESTOR PRESENTATION – AUGUST 6, 2014
NORTHERN MARCELLUS
IMPACT OF HOLDING PRODUCTION FLAT
$4 - $7 billion Cumulative net FCF over the next 10 years
$300 mm - 5 rigs Net capital required per year to hold gross production flat at 2.2 bcf/d
Assumes $4.00 and $5.00 NYMEX pricing and is fully burdened with differentials and cycle time
27 I INVESTOR PRESENTATION – AUGUST 6, 2014
SOUTHERN MARCELLUS
ASSET OVERVIEW
• ~2.7 bboe of net recoverable resources
• 250,000+ net acres
> 68% avg. WI, 57% avg. NRI
• 2Q’14 avg. net production of 58 mboe/d
> Up 67% YOY
• Averaged 1 operated rig and connected 9 gross wells in 2Q’14
• 1 - 2 operated rigs in 2014
• Added second rig in WV panhandle to delineate Utica dry gas potential
(1) 2Q’14 daily average net production
CHK Operated Rigs
Industry Rigs
CHK Leasehold
Production mix(1)
28 I INVESTOR PRESENTATION – AUGUST 6, 2014
SOUTHERN MARCELLUS
VALUE AND GROWTH OPPORTUNITY
• Potential to unlock significant value
> Combination of dry gas Utica and
liquids-rich S. Marcellus acreage
> Annual organic growth potential >50%
> Ramp activity into expanding capacity
Antero and Rice leasehold positions sourced from public information
$4 - $8 billion(1)
Valuation implied by market multiples Antero Rice CHK Leasehold Opportunity Outline
250,000+ Net Southern Marcellus acres not including 165,000+ net acres of stacked Utica potential
(1) Based on Antero’s market data as of 5/12/2014. Leasehold, production and locations sourced from public information
29 I INVESTOR PRESENTATION – AUGUST 6, 2014
• CHK and RKI Exploration & Production, LLC (RKI) announced an agreement to exchange
non operated interests in the Powder River Basin (PRB)
> Increases CHK’s holdings by 66,000 net acres and average working interest from 38% to 79%
> Consolidates position in the southern area, nearly all of which will be CHK operated
> Multiple stacked pay potential: >2 billion boe of gross recoverable resources
> Adds net incremental production of ~4.5 mboe per day
> CHK to pay $450 mm in cash on closing
• Niobrara Formation: Oil Growth on the Way, Rates of Return Rising
> 2015 oil growth engine: New gas processing plant in 4Q’14 will remove constraints
> 50% reduction in drilling cost per foot and cycle times over the past two years
> Longer laterals, completion improvements estimated to increase rates of return to >40%
> Shifting from wet gas/condensate drilling to fractured black oil window in 2H’14
• Upper Cretaceous Sands Starting to Deliver
> Three successful Sussex wells to date: Sussex I has produced ~230 mboe in 150 production days
> Recently completed Sussex III: 24-hour average IP >1,000 boe/d (85% oil)
> Targeting Sussex rates of return >50%, high oil content, favorable API gravity ~40-48°
> Further testing planned on Sussex, Teapot, Parkman and Shannon formations in 2H’14
POWDER RIVER BASIN – INCREASING EXPOSURE
IN A WORLD CLASS OIL PLAY
30 I INVESTOR PRESENTATION – AUGUST 6, 2014
CHK Operated
RKI Operated
POWDER RIVER BASIN –
RKI ACREAGE EXCHANGE
Pre-transaction Post-transaction
Pre-transaction Post-transaction
322,000 Net Acres 388,000
38% Avg. Working Interest 79%
10 mboe/d Net Daily Production 14.5 mboe/d
2014: 3 rigs Avg. Rig Count 2015: 7 - 9 rigs
CHK Avg. Working Interest = 38% CHK Avg. Working Interest = 79%
CHK Operated Rigs CHK Leasehold
31 I INVESTOR PRESENTATION – AUGUST 6, 2014
• Gross Recoverable Resources of >2.0 bboe
> Niobrara
• ~1,500 mmboe
• 50% to 70% oil/condensate
• Estimated 45° - 60° API gravity
> Upper Cretaceous(1)
• ~325 mmboe
• >75% oil/condensate
• Estimated 40°- 48° API gravity
> Additional Potential
• Frontier ~250 mmboe
• Excludes Mowry shale (source rock) upside
SOUTHERN PRB RESOURCE POTENTIAL
(1) Upper Cretaceous Sands include Sussex, Shannon, Teapot and Parkman
72%
28%
Niobrara
Upper Cretaceous / Frontier
% Recoverable Resources by Formation
32 I INVESTOR PRESENTATION – AUGUST 6, 2014
• Targeting avg. rate of return in excess of 40%
> Cycle times / drilling cost per ft. continue to decline
> Increasing lateral lengths (from 5,800 ft to 6,800 ft. on avg.)
> Enhanced completions through tighter cluster spacing and more proppant resulting in higher EUR/ft
NIOBRARA –
CONTINUOUSLY IMPROVING ECONOMICS
Cost/Ft. and Lateral Length D&C and ROR (%)
+20% EUR
33 I INVESTOR PRESENTATION – AUGUST 6, 2014
Sussex
focus
area is
~20 miles
long by
~5 miles
wide
SUCCESSFUL SUSSEX DELINEATION AND
ADDITIONAL UPPER CRETACEOUS TESTS
I
CHK Operated
RKI Operated
Sussex I •Peak 24 Hr. Rate: 1,335 bbls oil,
735 bbls NGL, 3.5 mmcf
•Cumulative prod.to date: 230 mboe
in 150 days (85% oil)
Sussex III •Peak 24 Hr. Rate: 877 bbls
oil, 35 bbls NGL, 0.5 mmcf
•Drilled in <17 days
Sussex II • Peak 24 Hr. Rate: 1,050
bbls oil, 115 bbls NGL,
1.5 mmcf
• Near-term activity
> 6 Sussex spuds in 2H’14
> 1 Parkman test 4Q’14
> 1 Teapot test 4Q’14
> 1 Shannon test 4Q’14
• Reached total depth on Sussex IV
> ~6,000 ft. lateral
• Currently drilling Sussex V
> ~9,200 ft. lateral planned
V IV
II
III
Sussex Formation
34 I INVESTOR PRESENTATION – AUGUST 6, 2014
$1,500
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
$396
$2,299
$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 $1.3692 to €1.00 at 6/30/2014 (3) All-in yield composed of 3.25% spread and 3mL
Convertibles Other Senior Notes
Sr. Debt: $11.8 billion
6/30/2014 WACD – 5.0%
Avg. Maturity: 5.4 years
$0
SENIOR NOTE PROFILE
35 I INVESTOR PRESENTATION – AUGUST 6, 2014
CHK’S HEDGING STRATEGY INCREASES
CASH FLOW CERTAINTY IN 2014
69% 65%
Natural Gas Oil
41%
Swaps
24% Three-Way
Collars
$4.10 - $4.37/mcf
NYMEX
$4.09/mcf
NYMEX
$4.50-$5.24/mcf
NYMEX
$94.25/bbl
NYMEX
• Ensures delivery of business strategy by securing prices
• Proactively managing basis
Downside protection for 2H’14 as of 7/31/2014
36 I INVESTOR PRESENTATION – AUGUST 6, 2014
• ~38% of estimated April - October 2014 natural gas production will receive an avg. basis diff. of ($0.68)/mcf
• ~10% of estimated April - October 2014 natural gas production will receive Gulf Coast linked pricing
• ~35% of April-October 2014E natural gas production sold in-basin under firm purchase agreements
NE MARCELLUS SALES POINTS AND
BASIS HEDGES
1Q’14A
Diff. to HH
Apr. – Oct. ‘14 Basis Hedges
Apr. – Oct. ‘14 Hedged Volumes
(mmcf/d)
Tetco M3/Transco z6 NYC $3.25 ($0.62) 240
Dominion South ($0.49) ($0.90) 30
WTD. Avg. Basis Hedged
April – Oct ‘14 ($0.68)
34%
9% 9% 3%
36%
9% Tetco M3/TCO z6 (NYC)
Dominion South Point
TGP Zn1 500 Line
TGP Zn4 200L
In-Basin Firm
In-Basin Floating
Estimated Apr. - Oct ‘14 NE Sales Points
37 I INVESTOR PRESENTATION – AUGUST 6, 2014
UTICA AND SOUTHERN MARCELLUS SALES POINTS
1Q’14A
Diff. to HH
Apr. – Oct. ‘14 Basis Hedges
Apr. – Oct. ‘14 Hedged Volumes
(mmcf/d)
TCO ($0.03) ($0.22) 105
Dominion South ($0.49) ($0.90) 45
WTD. Avg. Basis Hedged
Apr. – Oct. ‘14 ($0.42/mcf)
39%
18%
21%
6%
10% 6%
TGP Zn1 500L (Gulf Coast)
Dominion South Point
TGP Zn4 200L
TETCO M3
TCO
TETCo M2
30%
39%
10%
13%
8% TGP Zn1 500L (Gulf Coast)
Tetco WLA (Gulf Coast)
Dominion South Point
TGP Zn4 200L
TCO
Estimated Apr. – Oct. ‘14 Sales Points Estimated 2015 Sales Points
• ~31% of estimated Apr. - Oct. 2014 natural gas production will receive an avg. differential of ($0.42)/mcf
• ~40% and ~70% of 2014E and 2015E natural gas will receive Gulf Coast linked pricing, respectively
38 I INVESTOR PRESENTATION – AUGUST 6, 2014
ADJUSTED PRODUCTION GROWTH
Oil (mmbbls) 41.1 (5.6) 35.5 11 – 15%
NGL (mmbbls) 20.9 (1.9) 19 63 – 68%
Natural Gas (bcf) 1,095 (99.5) 995.5 4 – 6%
Total (mmboe) 244.4 (24) 220.4 9 – 12%
2014E Adjusted
Production Growth
2013 Reported
Production
E&P
Sales
2013 Adjusted
Production
Asset Sale Adjustments (mmboe) 239 - 246
2014E
Adjusted
Production
2013
Adjusted
Production
220
244
2013
Reported
Production
(10.9)
(13.1)
2013 E&P
Sales
2014 E&P
Sales
39 I INVESTOR PRESENTATION – AUGUST 6, 2014
(1) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The
company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: (i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information
regarding these types of items. (2) In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP
($ in mm, except per share data)
Three Months Ended: 6/30/2014 6/30/2013
Net income available to common stockholders $145 $457
Adjustments, net of tax: Unrealized (gains) losses on derivatives (19) (325)
Restructuring and other termination costs 20 5
Impairments of fixed assets and other 25 143
Net gains on sales of fixed assets (57) (68)
Impairments of investments 3 –
Net (gains) losses on sales of investments – 6
Losses on purchases of debt and extinguishment of other financing 120 44
Other (2) 3
Adjusted net income available to common stockholders(1) $235 $265 Preferred stock dividends 43 43
Premium on purchase of preferred shares of a subsidiary – 69
Earnings allocated to participating securities 3 11
Total adjusted net income attributable to CHK $281 $388
Weighted average fully diluted shares outstanding(2) 776 763
Adjusted earnings per share assuming dilution(1) $0.36 $0.51
RECONCILIATION
40 I INVESTOR PRESENTATION – AUGUST 6, 2014
(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 ebitda 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.
($ in mm)
Three Months Ended: 6/30/2014 6/30/2013
Cash provided by operating activities $1,352 $1,281 Changes in assets and liabilities (83) 85
Operating cash flow(1)
$1,269 $1,366
Net income $230 $625 Interest expense 27 104
Income tax expense 141 384
Depreciation and amortization of other assets 79 76
Natural gas, oil and NGL depreciation, depletion and amortization 661 645
EBITDA(2)
$1,138 $1,834
Adjustments: Unrealized losses on natural gas, oil and NGL derivatives – (576)
Restructuring and other termination costs 33 7
Impairments of fixed assets and other 40 231 Net gains on sales of fixed assets (93) (109)
Impairments of investments 5 –
Net (gains) losses on sales of investments – 10
Losses on purchases of debt and extinguishment of other financing 195 70
Net income attributable to noncontrolling interests (39) (45)
Other (2) 2
Adjusted EBITDA(3) $1,277 $1,424
RECONCILIATION
41 I INVESTOR PRESENTATION – AUGUST 6, 2014
CORPORATE INFORMATION
PUBLICLY TRADED SECURITIES CUSIP TICKER
9.5% Senior Notes due 2015 #165167CD7 CHK15K
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
GARY T. CLARK, CFA Vice President — Investor Relations and Research
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
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