Chesapeake Energy Corporation (NYSE:CHK) today reported
financial and operational results for the 2014 second quarter. Key
information related to the second quarter is as follows:
- Company reports adjusted net income
of $0.36 per fully diluted share and adjusted ebitda of $1.277
billion
- Average production of approximately
695,000 boe per day increases 13% year over year, adjusted for
asset sales
- Average oil production of
approximately 113,400 bbls per day increases 12% year over year,
adjusted for asset sales
- Total capital expenditures of $1.3
billion decrease 27% year over year
- Company increases midpoint of 2014
production outlook by 10,000 boe per day, reiterates 2014 total
capex of $5.0 to $5.4 billion
- Spin-off of oilfield services
business (NYSE:SSE) completed June 30, 2014
For the 2014 second quarter, Chesapeake reported net income
available to common stockholders of $145 million, or $0.22 per
fully diluted share. Items typically excluded by securities
analysts in their earnings estimates reduced net income available
to common stockholders for the 2014 second quarter by approximately
$90 million on an after-tax basis and are presented on Page 13 of
this release. The primary component of this reduction to net income
was a loss on the repurchase of debt securities associated with our
April 2014 debt refinancing, partially offset by net gains on sales
of fixed assets. Adjusting for these items, 2014 second quarter net
income available to common stockholders was $235 million, or $0.36
per fully diluted share, which compares to adjusted net income
available to common stockholders of $265 million, or $0.51 per
fully diluted share, in the 2013 second quarter.
Adjusted ebitda was $1.277 billion in the 2014 second quarter,
compared to $1.424 billion in the 2013 second quarter. Operating
cash flow, which is cash flow provided by operating activities
before changes in assets and liabilities, was $1.269 billion in the
2014 second quarter, compared to $1.366 billion in the 2013 second
quarter. The year-over-year decreases in adjusted ebitda and
operating cash flow were primarily the result of higher production
and lower per unit costs, which were more than offset by the effect
of lower realized oil, natural gas and natural gas liquids (NGL)
prices.
Adjusted net income available to common stockholders, operating
cash flow, ebitda and adjusted ebitda are non-GAAP financial
measures. Reconciliations of these measures to comparable financial
measures calculated in accordance with generally accepted
accounting principles are provided on pages 13 - 17 of this
release.
Doug Lawler, Chesapeake’s Chief Executive Officer, commented,
"Chesapeake delivered solid organic production growth in the
quarter while continuing to demonstrate capital discipline and
efficiency. As a result, we are increasing our 2014 production
outlook while leaving our capital budget unchanged. In the 2014
second half, we plan to connect approximately 35% more wells to
sales than we connected in the first half of the year. As our pace
of well connections accelerates, we expect our production growth
trajectory will increase accordingly and we anticipate our year-end
2014 exit rate will exceed 730,000 boe per day."
2014 Second Quarter Average Daily Production of Approximately
695,000 Boe Increases 13% Year over Year, Adjusted for Asset
Sales
Chesapeake’s daily production for the 2014 second quarter
averaged 694,650 barrels of oil equivalent (boe), a year-over-year
increase of 13%, adjusted for asset sales. Average daily production
consisted of approximately 113,400 barrels (bbls) of oil, 84,300
bbls of NGL and 3.0 billion cubic feet (bcf) of natural gas.
On an adjusted basis, 2014 second quarter average daily oil
production increased 12% year over year, average daily NGL
production increased 72% year over year and natural gas production
increased 7% year over year.
Chesapeake is increasing the midpoint of its expected 2014 daily
production rate outlook by 10,000 boe, or 1.5%, to between 685,000
and 705,000 boe per day. The increase in production is partially
attributable to better production trends in the first half of 2014,
coupled with an increase in forecasted well connections during the
second half of 2014. A change in the timing of announced
divestitures and the acreage swap with RKI Exploration &
Production, LLC (RKI), as described below, also impacted the
outlook increase.
Recent Strategic Transactions
On June 30, 2014, Chesapeake completed the spin-off of its
oilfield services business into an independent publicly traded
company, Seventy Seven Energy Inc. (NYSE:SSE). After the close of
business on June 30, 2014, Chesapeake distributed to its
shareholders one share of SSE common stock for every 14 shares of
Chesapeake common stock held as of June 19, 2014, the record date.
In conjunction with the spin-off, Chesapeake removed $1.1 billion
of debt associated with SSE from its balance sheet, the effect of
which was reflected as of June 30, 2014.
On July 29, 2014, Chesapeake repurchased all of the outstanding
preferred shares of its unrestricted subsidiary CHK Utica, L.L.C.
(CHK Utica) from third-party preferred shareholders. Chesapeake
paid approximately $1.26 billion to repurchase 1,060,000 preferred
shares of CHK Utica. The transaction retired Chesapeake’s highest
cost leverage instrument and eliminated approximately $75 million
in annual cash dividend payments to third-party preferred
shareholders.
On July 29, 2014, Chesapeake announced that it had entered into
an agreement with RKI to exchange Chesapeake's nonoperated northern
Powder River Basin (PRB) acreage for RKI's southern PRB acreage
that is operated by Chesapeake. The transaction is expected to
increase Chesapeake's PRB holdings by 66,000 net acres and average
working interest from 38% to 79%. In addition to the exchange of
acreage, Chesapeake will pay RKI $450 million in cash. The
transaction, which is subject to certain closing conditions
including the receipt of third-party consents, is expected to close
in August 2014.
Asset Sales Update
During the 2014 second quarter, the company received total
proceeds of approximately $675 million from the sale of noncore
assets, including $362 million of net proceeds from the sale of
compression assets to Exterran Partners, L.P. (NASDAQ:EXLP).
In the 2014 second half, Chesapeake expects to receive more than
$700 million in proceeds from various asset sales that have closed,
or are underway. These transactions are expected to include noncore
E&P assets in southwestern Pennsylvania, South Central
Oklahoma, East Texas and South Texas, as well as additional
compression assets and other miscellaneous real estate and
equipment.
Chesapeake continues to pursue opportunities to high-grade its
portfolio while focusing on assets that best align with its
strategy of profitable growth from captured resources. The company
believes its targeted asset dispositions will be value-accretive
and enable it to further reduce financial complexity and lower
overall leverage.
Capital Spending and Cost Overview
Chesapeake's total capital expenditures in the 2014 second
quarter were approximately $1.315 billion, of which drilling and
completion capital expenditures were approximately $1.131 billion.
This level of expenditures represents an increase of approximately
$402 million, or 55%, compared to the 2014 first quarter. The
sequential increase is primarily the result of higher drilling and
completion activity during the 2014 second quarter, including a
significant increase in nonoperated drilling and completion
activity.
In the 2014 second quarter, net expenditures for the acquisition
of unproved properties and geological and geophysical costs were
approximately $54 million. Other capital expenditures were
approximately $130 million, of which $79 million was attributable
to capital spending in its former oilfield services business prior
to the June 30, 2014 spin-off. In addition, the company purchased
rigs and compressors previously sold under long-term lease
arrangements for approximately $82 million as part of its strategic
initiative to reduce complexity and future commitments as well as
to facilitate asset sales and the SSE spin-off.
Chesapeake spud a total of 324 gross wells and connected 275
gross wells to sales during the 2014 second quarter, compared to
299 gross wells spud and 249 gross wells connected to sales during
the 2014 first quarter. In the second half of 2014, the company
plans to connect to sales approximately 35% more wells than were
connected in the first half of 2014, and anticipates investing
approximately 40% more capital on drilling and completions. The
company reiterates its 2014 full-year total capital expenditure
guidance of $5.0 - $5.4 billion, excluding capitalized
interest.
Chesapeake's focus on cost discipline continued to generate
reductions in production and general and administrative (G&A)
expenses. Average production expenses during the 2014 second
quarter were $4.46 per boe, a decrease of 5% from the 2013 second
quarter. G&A expenses (including share-based compensation)
during the 2014 second quarter were $1.43 per boe, a decrease of
17% from the 2013 second quarter. Interest expense (excluding
unrealized gains or losses on interest rate derivatives) during the
2014 second quarter was $0.92 per boe, an 8% increase from the 2013
second quarter, as the company capitalized a smaller percentage of
its interest cost due to a decrease in unevaluated natural gas and
oil properties.
A summary of the company’s guidance for 2014 is provided in the
Outlook dated August 6, 2014, attached to this release as Schedule
"A” beginning on Page 18.
Operational Update - Southern Division
Eagle Ford Shale (South
Texas): Eagle Ford net production averaged
approximately 91,000 boe per day (200,000 gross operated boe per
day) during the 2014 second quarter. Adjusted for asset sales, this
represents an increase of 15% year over year and 4% sequentially.
Approximately 64% of the company’s Eagle Ford production in the
2014 second quarter was oil, 14% was NGL and 22% was natural gas.
Current field estimated production rates for the Eagle Ford are
more than 101,000 boe per day during the final week of July as
increased activity continues to drive higher production.
Chesapeake operated an average of 22 rigs (two of which were
spudder rigs) and connected 104 gross wells to sales during the
2014 second quarter in the Eagle Ford, compared to 18 average
operated rigs and 81 gross wells connected to sales during the 2014
first quarter. The average peak production rate of the 104 wells
that commenced first production in the Eagle Ford during the 2014
second quarter was approximately 825 boe per day.
Mid-Continent (Oklahoma, Texas
Panhandle, southern Kansas): Chesapeake's net
production in the Mid-Continent during the 2014 second quarter
averaged 98,000 boe per day (180,000 gross operated boe per day).
Approximately 33% of the company’s Mid-Continent production during
the 2014 second quarter was oil, 20% was NGL and 47% was natural
gas.
During the 2014 second quarter, Chesapeake operated an average
of 18 rigs (one of which was a spudder rig) and connected 56 gross
wells to sales in the Mid-Continent, compared to 17 average
operated rigs and 52 gross wells connected to sales during the 2014
first quarter. The average peak production rate of the 56 wells
that commenced first production in the Mid-Continent during the
2014 second quarter was approximately 710 boe per day.
Haynesville Shale (Northwest Louisiana,
East Texas): Chesapeake’s 2014 second quarter
average net production in the Haynesville was approximately 508
million cubic feet of natural gas equivalent (mmcfe) per day (785
gross operated mmcfe per day). Adjusted for 2013 asset sales, this
represents a decrease of 26% year over year and a 3% increase
sequentially. All of the company's production in the Haynesville
consists of natural gas.
During the 2014 second quarter, Chesapeake operated an average
of eight rigs and connected 13 gross wells to sales in the
Haynesville, compared to seven average operated rigs and seven
gross wells connected to sales during the 2014 first quarter. The
average peak production rate of the 13 wells that commenced first
production in the Haynesville during the 2014 second quarter was
approximately 12.6 mmcfe per day.
During the 2014 second quarter, Chesapeake brought on to
production nine cross unit lateral tests, which enabled the company
to increase lateral length by approximately 17% and access
incremental resources that would have otherwise been left
undeveloped. The company is encouraged by the initial results of
these cross unit laterals and will continue to monitor
performance.
Operational Update - Northern Division
Utica Shale (Ohio, Pennsylvania, West
Virginia): Utica net production averaged
approximately 67,000 boe per day (125,000 gross operated boe per
day) during the 2014 second quarter, an increase of 373% year over
year and 34% sequentially. Approximately 10% of the company’s Utica
production during the 2014 second quarter was oil, 30% was NGL and
60% was natural gas.
During the 2014 second quarter, Chesapeake operated an average
of eight rigs and connected 48 gross wells to sales in the Utica,
compared to an average of nine operated rigs and 47 gross wells
connected to sales during the 2014 first quarter. The average peak
production rate of the 48 wells that commenced first production in
the Utica during the 2014 second quarter was approximately 1,200
boe per day.
As of June 30, 2014, the company had 210 wells awaiting pipeline
connection or in various stages of completion in the Utica. In June
2014, the third phase of the Kensington gas processing plant,
located in Columbiana County, Ohio, was placed into service. This
incremental capacity will enable the company to connect more Utica
wells to sales during the 2014 second half and begin to reduce its
inventory of nonproducing wells to a more normalized working
level.
Northern Marcellus Shale
(Pennsylvania): Average net production in the
northern Marcellus was approximately 878 mmcfe per day (2,145 gross
operated mmcfe per day), an increase of 12% year over year and a
decrease of 3% sequentially. The sequential decrease was primarily
the result of significant downtime at a large pipeline compressor
station in June. All of the company's production in the northern
Marcellus consists of natural gas.
During the 2014 second quarter, Chesapeake operated an average
of six rigs and connected 21 gross wells to sales in the northern
Marcellus, compared to five average operated rigs and 22 gross
wells connected to sales during the 2014 first quarter. The average
peak production rate of the 21 wells that commenced first
production in the northern Marcellus during the 2014 second quarter
was approximately 13.6 mmcfe per day.
As of June 30, 2014, the company had 120 wells awaiting pipeline
connection or in various stages of completion in the northern
Marcellus.
Southern Marcellus Shale (Pennsylvania,
West Virginia): Average net production in the
southern Marcellus was approximately 58,000 boe per day (95,400
gross operated boe per day), an increase of 67% year over year and
an increase of 5% sequentially. Approximately 9% of the company’s
southern Marcellus production during the 2014 second quarter was
oil, 34% was NGL and 57% was natural gas.
During the 2014 second quarter, Chesapeake operated an average
of one rig and connected nine gross wells to sales in the southern
Marcellus, compared to two average operated rigs and 11 gross wells
connected to sales during the 2014 first quarter. The average peak
production rate of the nine wells that commenced first production
in the southern Marcellus during the 2014 second quarter was
approximately 1,875 boe per day. Chesapeake recently added a second
rig in the southern Marcellus where its primary objective will be
to delineate the dry Utica formation in the West Virginia
Panhandle.
Powder River Basin
(Wyoming): Average net production in the PRB was
approximately 11,000 boe per day (19,150 gross operated boe per
day), an increase of 479% year over year and an increase of 17%
sequentially. Approximately 51% of the company’s Powder River Basin
production during the 2014 second quarter was oil, 16% was NGL and
33% was natural gas.
During the 2014 second quarter, Chesapeake operated an average
of three rigs and connected 11 gross wells to sales in the Powder
River Basin, compared to four average operated rigs and 13 gross
wells connected to sales during the 2014 first quarter. The average
peak production rate of the 11 wells that commenced first
production in the Powder River Basin during the 2014 second quarter
was approximately 1,765 boe per day.
Chesapeake intends to begin adding more rigs in the Powder River
Basin during the 2015 first quarter, and expects to average
approximately seven to nine rigs drilling throughout 2015. The
company expects that its production from the Powder River Basin
will be relatively constrained until the Buckinghorse gas
processing plant is placed into service during the 2014 fourth
quarter.
As of June 30, 2014, the company had 47 wells awaiting pipeline
connection or in various stages of completion in the Powder River
Basin.
Key Financial and Operational
Results
The table below summarizes Chesapeake’s
key financial and operational results during the 2014 second
quarter and compares them to results in prior periods.
Three Months Ended 06/30/14 03/31/14
06/30/13 Oil equivalent production (in mmboe) 63.2 60.8 61.6
Oil production (in mmbbls) 10.3 9.9 10.5 Average realized oil price
($/bbl)(a) 85.23 85.08 93.81 Oil as % of total production 16 16 17
NGL production (in mmbbls) 7.7 7.6 4.8 Average realized NGL price
($/bbl)(a) 21.03 29.23 24.22 NGL as % of total production 12 13 8
Natural gas production (in bcf) 271 260 278 Average realized
natural gas price ($/mcf)(a) 2.45 3.27 2.62 Natural gas as % of
total production 72 71 75 Production expenses ($/boe) (4.46 ) (4.73
) (4.68 ) Production taxes ($/boe) (1.14 ) (0.83 ) (0.95 ) General
and administrative costs ($/boe)(b) (1.25 ) (1.09 ) (1.49 )
Share-based compensation ($/boe) (0.18 ) (0.21 ) (0.24 ) DD&A
of natural gas and liquids properties ($/boe) (10.45 ) (10.33 )
(10.48 ) DD&A of other assets ($/boe) (1.25 ) (1.29 ) (1.23 )
Interest expense ($/boe)(a) (0.92 ) (0.90 ) (0.85 ) Marketing,
gathering and compression net margin
($ in millions)(c)
1 35 29 Oilfield services net margin ($ in millions)(c) 69 45 35
Operating cash flow ($ in millions)(d) 1,269 1,614 1,366 Operating
cash flow ($/boe) 20.07 26.55 22.19 Adjusted ebitda ($ in
millions)(e) 1,277 1,515 1,424 Adjusted ebitda ($/boe) 20.20 24.94
23.14 Net income available to common stockholders
($ in millions)
145 374 457 Earnings per share – diluted ($) 0.22 0.54 0.66
Adjusted net income available to common
stockholders ($ in millions)(f)
235 405 265 Adjusted earnings per share – diluted ($) 0.36 0.59
0.51 Total capital expenditures ($ in millions) 1,315 851 1,810
Capitalized interest ($ in millions) 155 178 210
(a) Includes the effects of
realized gains (losses) from hedging, but excludes the effects of
unrealized gains (losses) from hedging.
(b) Excludes expenses
associated with share-based compensation and restructuring and
other termination costs.
(c) Includes revenue and
operating expenses and excludes depreciation and amortization of
other assets.
(d) Defined as cash flow
provided by operating activities before changes in assets and
liabilities.
(e) Defined as net income
before interest expense, income taxes and depreciation, depletion
and amortization expense, as adjusted to remove the effects of
certain items detailed on Page 17.
(f) Defined as net income
available to common stockholders, as adjusted to remove the effects
of certain items detailed on Page 13.
2014 Second Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday, August 6, 2014, at 9:00 am EDT. The telephone number to
access the conference call is 913-312-1469 or toll-free
888-778-8903. The passcode for the call is 3038618.
We encourage those who would like to participate in the call to
place calls between 8:50 and 9:00 am EDT. For those unable to
participate in the conference call, a replay will be available for
audio playback at 2:00 pm EDT on Wednesday, August 6, 2014, and
will run through 2:00 pm EDT on Wednesday, August 20, 2014. The
number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is
3038618. The conference call will also be webcast live on
Chesapeake’s website at www.chk.com in the "Events” subsection of
the "Investors” section of the website.
Chesapeake Energy Corporation (NYSE:CHK) is the
second-largest producer of natural gas and the 10th largest
producer of oil and natural gas liquids in the U.S.
Headquartered in Oklahoma City, the company's operations are
focused on discovering and developing its large and geographically
diverse resource base of unconventional natural gas and oil assets
onshore in the U.S. The company also owns substantial
marketing and compression businesses. Further information is
available at www.chk.com where Chesapeake routinely
posts announcements, updates, events, investor information,
presentations and news releases.
This news release and the accompanying Outlook include
"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. They include
statements that give our current expectations or forecasts of
future events, production, production growth and well connection
forecasts, estimates of operating costs, planned development
drilling and expected drilling cost reductions, capital
expenditures, expected efficiency gains, anticipated asset sales
and proceeds to be received therefrom, projected cash flow and
liquidity, business strategy and other plans and objectives for
future operations, and the assumptions on which such statements are
based. 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.
In addition, 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 also dependent upon many assumptions, including
estimates of production decline rates from existing wells and the
outcome of future drilling activity. Further, the timing of and
amount of proceeds from future asset sales, which are subject to
changes in market conditions and other factors beyond our control,
will affect our ability to further reduce financial leverage and
complexity. The transaction with RKI is subject to closing
conditions, including third-party consents, and it 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 news release, and we undertake no obligation
to update any of the information provided in this release or the
accompanying Outlook, except as required by applicable law.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS
($ in millions, except per share
data)
(unaudited)
Three Months EndedJune
30,
2014 2013 REVENUES: Natural gas, oil and NGL $
1,704 $ 2,406 Marketing, gathering and compression 3,167 2,057
Oilfield services 281 212 Total Revenues 5,152
4,675
OPERATING EXPENSES: Natural gas, oil and
NGL production 282 288 Production taxes 72 59 Marketing, gathering
and compression 3,166 2,028 Oilfield services 212 177 General and
administrative 90 106 Restructuring and other termination costs 33
7
Natural gas, oil and NGL depreciation,
depletion and amortization
661 645 Depreciation and amortization of other assets 79 76
Impairments of fixed assets and other 40 231 Net gains on sales of
fixed assets (93 ) (109 ) Total Operating Expenses 4,542
3,508
INCOME FROM OPERATIONS 610 1,167
OTHER INCOME (EXPENSE): Interest expense (27 )
(104 ) Earnings (losses) on investments (24 ) 23 Net losses on
sales of investments — (10 ) Losses on purchases of debt (195 ) (70
) Other income 7 3 Total Other Expense (239 ) (158 )
INCOME BEFORE INCOME TAXES 371 1,009
INCOME TAX EXPENSE: Current income taxes 5 2 Deferred
income taxes 136 382 Total Income Tax Expense 141
384
NET INCOME 230 625 Net
income attributable to noncontrolling interests (39 ) (45 )
NET INCOME ATTRIBUTABLE TO CHESAPEAKE 191 580
Preferred stock dividends (43 ) (43 ) Premium on purchase of
preferred shares of a subsidiary — (69 ) Earnings allocated to
participating securities (3 ) (11 )
NET INCOME AVAILABLE
TO COMMON STOCKHOLDERS $ 145 $ 457
EARNINGS PER COMMON SHARE: Basic $ 0.22 $ 0.70
Diluted $ 0.22 $ 0.66
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Basic 659 653 Diluted 659 760
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS
($ in millions, except per share
data)
(unaudited)
Six Months
Ended
June 30,
2014 2013 REVENUES: Natural gas, oil and NGL $
3,471 $ 3,858 Marketing, gathering and compression 6,182 3,838
Oilfield services 545 402 Total Revenues 10,198
8,098
OPERATING EXPENSES: Natural gas,
oil and NGL production 570 595 Production taxes 122 112 Marketing,
gathering and compression 6,147 3,772 Oilfield services 431 332
General and administrative 169 216 Restructuring and other
termination costs 26 140
Natural gas, oil and NGL depreciation,
depletion and amortization
1,288 1,293 Depreciation and amortization of other assets 157 154
Impairments of fixed assets and other 60 258 Net gains on sales of
fixed assets (115 ) (158 ) Total Operating Expenses 8,855
6,714
INCOME FROM OPERATIONS 1,343
1,384
OTHER INCOME (EXPENSE): Interest expense
(66 ) (124 ) Losses on investments (45 ) (14 ) Net gains (losses)
on sales of investments 67 (10 ) Losses on purchases of debt (195 )
(70 ) Other income 13 8 Total Other Expense (226 )
(210 )
INCOME BEFORE INCOME TAXES 1,117 1,174
INCOME TAX EXPENSE: Current income taxes 8 3
Deferred income taxes 413 443 Total Income Tax
Expense 421 446
NET INCOME 696 728
Net income attributable to noncontrolling interests (80 )
(89 )
NET INCOME ATTRIBUTABLE TO CHESAPEAKE 616
639 Preferred stock dividends (86 ) (86 )
Premium on purchase of preferred shares of a subsidiary — (69 )
Earnings allocated to participating securities (12 ) (11 )
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 518 $
473
EARNINGS PER COMMON SHARE: Basic $ 0.79
$ 0.72 Diluted $ 0.78 $ 0.72
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING
(in millions): Basic 658 653 Diluted 760
653
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE
SHEETS
($ in millions)
(unaudited)
June 30,2014
December 31, 2013
Cash and cash equivalents $ 1,462 $ 837 Other current assets
2,908 2,819 Total Current Assets 4,370 3,656
Property and equipment, (net) 36,011 37,134 Other assets 746
992 Total Assets $ 41,127 $ 41,782 Current
liabilities $ 5,792 $ 5,515 Long-term debt, net of discounts 11,549
12,886 Other long-term liabilities 1,688 1,834 Deferred income tax
liabilities 3,773 3,407 Total Liabilities 22,802
23,642 Preferred stock 3,062 3,062 Noncontrolling interests
2,123 2,145 Common stock and other stockholders’ equity 13,140
12,933 Total Equity 18,325 18,140 Total
Liabilities and Equity $ 41,127 $ 41,782 Common
Shares Outstanding (in millions) 664 664
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
June 30,2014
December 31,2013
Total debt, net of unrestricted cash $ 10,087 $ 12,049
Preferred stock 3,062 3,062 Noncontrolling interests(a) 2,123 2,145
Common stock and other stockholders’ equity 13,140
12,933 Total $ 28,412 $ 30,189
Total debt to capitalization ratio 36 % 40 %
(a) Includes third-party ownership as
follows:
CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015 CHK Utica,
L.L.C. 807 807 Chesapeake Granite Wash Trust 294 314 Other 7
9 Total $ 2,123 $ 2,145
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS, OIL
AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
Three Months EndedJune
30,
Six Months EndedJune 30,
2014 2013 2014 2013 Net
Production: Natural gas (bcf) 271.3 277.6 531.4 550.8 Oil
(mmbbl) 10.3 10.5 20.2 19.8 NGL (mmbbl) 7.7 4.8 15.2 9.6 Oil
equivalent (mmboe) 63.2 61.6 124.0 121.2
Natural Gas, Oil
and NGL Sales ($ in millions): Natural gas sales $ 750 $ 779 $
1,754 $ 1,352 Natural gas derivatives – realized gains (losses)(a)
(86 ) (53 ) (240 ) (45 ) Natural gas derivatives – unrealized gains
(losses)(a) 113 347 (41 ) 68 Total Natural Gas
Sales 777 1,073 1,473 1,375 Oil
sales 1,006 975 1,928 1,859 Oil derivatives – realized gains
(losses)(a) (127 ) 14 (210 ) 10 Oil derivatives – unrealized gains
(losses)(a) (113 ) 229 (103 ) 361 Total Oil Sales 766
1,218 1,615 2,230 NGL sales 161
115 383 253 Total NGL Sales 161
115 383 253 Total Natural Gas, Oil and NGL
Sales $ 1,704 $ 2,406 $ 3,471 $ 3,858
Average Sales Price – excluding gains (losses) on
derivatives: Natural gas ($ per mcf) $ 2.76 $ 2.81 $ 3.30 $
2.45 Oil ($ per bbl) $ 97.49 $ 92.53 $ 95.59 $ 93.79 NGL ($ per
bbl) $ 21.03 $ 24.22 $ 25.10 $ 26.26 Oil equivalent ($ per boe) $
30.32 $ 30.36 $ 32.79 $ 28.57
Average Sales Price –
including realized gains (losses) on derivatives: Natural gas
($ per mcf) $ 2.45 $ 2.62 $ 2.85 $ 2.37 Oil ($ per bbl) $ 85.23 $
93.81 $ 85.16 $ 94.29 NGL ($ per bbl) $ 21.03 $ 24.22 $ 25.10 $
26.26 Oil equivalent ($ per boe) $ 26.97 $ 29.73 $ 29.16 $ 28.28
Interest Expense (Income) ($ in millions):
Interest(b) $ 61 $ 54 $ 119 $ 70 Derivatives – realized (gains)
losses(c) (3 ) (1 ) (6 ) (3 ) Derivatives – unrealized (gains)
losses(c) (31 ) 51 (47 ) 57 Total Interest Expense $
27 $ 104 $ 66 $ 124
(a) Realized gains and losses include the
following items: (i) settlements of nondesignated derivatives
related to current period production revenues, (ii) prior period
settlements for option premiums and for early-terminated
derivatives originally scheduled to settle against current period
production revenues, and (iii) gains and losses related to
de-designated cash flow hedges originally designated to settle
against current period production revenues. Unrealized gains and
losses include the change in fair value of open derivatives
scheduled to settle against future period production revenues
offset by amounts reclassified as realized gains and losses during
the period. Although we no longer designate our derivatives as cash
flow hedges for accounting purposes, we believe these definitions
are useful to management and investors in determining the
effectiveness of our price risk management program.
(b) Net of amounts capitalized.
(c) Realized (gains) losses include
settlements related to the current period interest accrual and the
effect of (gains) losses on early termination trades. Unrealized
(gains) losses include changes in the fair value of open interest
rate derivatives offset by amounts reclassified to realized (gains)
losses during the period.
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW
DATA
($ in millions)
(unaudited)
THREE MONTHS
ENDED:
June 30,2014
June 30,2013
Beginning cash $ 1,004 $ 33
Cash provided by operating activities 1,352 1,281
Cash flows from investing activities:
Drilling and completion costs on proved
and unproved properties(a)
(1,082 ) (1,551 ) Acquisition of proved and unproved properties(b)
(169 ) (256 ) Sale of proved and unproved properties 198 1,691
Geological and geophysical costs (16 ) (15 ) Cash paid to purchase
leased rigs and compressors (82 ) (3 ) Additions to other property
and equipment (56 ) (152 ) Property and equipment deposits (45 )
(21 ) Proceeds from sales of other assets 474 258 Additions to
investments (2 ) (1 ) Proceeds from sales of investments — 102
Other (1 ) 118
Total cash provided by (used in) investing
activities (781 ) 170
Cash used in financing
activities (113 ) (807 )
Change in cash and cash
equivalents 458 644
Ending cash $ 1,462
$ 677
(a) Includes capitalized interest of $9
million and $17 million for the three months ended June 30,
2014 and 2013, respectively.
(b) Includes capitalized interest of $140
million and $173 million for the three months ended June 30,
2014 and 2013, respectively.
SIX
MONTHS ENDED: June 30,2014 June
30,2013 Beginning cash $ 837 $ 287
Cash provided by operating activities 2,643
2,205
Cash flows from investing
activities:
Drilling and completion costs on proved
and unproved properties(a)
(1,976 ) (3,117 ) Acquisition of proved and unproved properties(b)
(348 ) (511 ) Sale of proved and unproved properties 240 1,856
Geological and geophysical costs (20 ) (28 ) Cash paid to purchase
leased rigs and compressors (422 ) (3 ) Additions to other property
and equipment (153 ) (482 ) Property and equipment deposits (45 )
(21 ) Proceeds from sales of other assets 713 459 Additions to
investments (5 ) (4 ) Proceeds from sales of investments 239 102
Other (3 ) 174
Total cash used in investing
activities (1,780 ) (1,575 )
Cash used in financing
activities (238 ) (240 )
Change in cash and cash
equivalents 625 390
Ending cash $ 1,462
$ 677
(a) Includes capitalized interest of $21
million and $32 million for the six months ended June 30, 2014
and 2013, respectively.
(b) Includes capitalized interest of $298
million and $380 million for the six months ended June 30,
2014 and 2013, respectively.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME
AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share
data)
(unaudited)
THREE MONTHS ENDED:
June 30,2014
March 31,2014
June 30,2013
Net income available to common
stockholders
$ 145 $ 374 $ 457
Adjustments, net of tax: Unrealized
(gains) losses on derivatives (19 ) 80 (325 ) Restructuring and
other termination costs 20 (4 ) 5 Impairments of fixed assets and
other 25 12 143 Net gains on sales of fixed assets (57 ) (14 ) (68
) Impairments of investments 3 — — Net (gains) losses on sales of
investments — (42 ) 6 Losses on purchases of debt and
extinguishment of other financing 120 — 44 Other (2 ) (1 ) 3
Adjusted net income available to common
stockholders(a) 235 405 265 Preferred stock dividends
43 43 43 Premium on purchase of preferred shares of a subsidiary —
— 69 Earnings allocated to participating securities 3 8
11
Total adjusted net income attributable to
Chesapeake $ 281 $ 456 $ 388
Weighted average fully diluted shares
outstanding (in millions)(b)
776 767 763
Adjusted earnings per share assuming
dilution(a) $ 0.36 $ 0.59 $ 0.51
(a) 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.
(b) Weighted average fully diluted shares
outstanding include shares that were considered antidilutive for
calculating earnings per share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME
AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share
data)
(unaudited)
SIX MONTHS
ENDED:
June 30,2014
June 30,2013
Net income available to commonstockholders $
518 $ 473
Adjustments, net of tax: Unrealized (gains)
losses on derivatives 61 (230 ) Restructuring and other termination
costs 16 87 Impairments of fixed assets and other 37 160 Net gains
on sales of fixed assets (72 ) (98 ) Impairments of investments 3 6
Net (gains) losses on sales of investments (42 ) 6 Losses on
purchases of debt and extinguishment of other financing 121 44
Other (3 ) —
Adjusted net income available to common
stockholders(a) 639 448 Preferred stock dividends 86
86 Premium on purchase of preferred shares of a subsidiary — 69
Earnings allocated to participating securities 12 11
Total adjusted net income attributable to Chesapeake $ 737
$ 614
Weighted average fully diluted
shares outstanding (in millions)(b) 776 764
Adjusted earnings per share assuming
dilution(a) $ 0.95 $ 0.80
(a) 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.
(b) Weighted average fully diluted shares
outstanding include shares that were considered antidilutive for
calculating earnings per share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW
AND EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED:
June 30,
2014
March 31,
2014
June 30,
2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,352 $ 1,291
$ 1,281 Changes in assets and liabilities (83 ) 323 85
OPERATING CASH FLOW(a) $ 1,269 $ 1,614
$ 1,366
THREE MONTHS ENDED:
June 30,
2014
March 31,
2014
June 30,
2013
NET INCOME $ 230 $ 466 $ 625 Interest expense 27 39
104 Income tax expense 141 280 384 Depreciation and amortization of
other assets 79 78 76 Natural gas, oil and NGL depreciation,
depletion and amortization 661 628 645
EBITDA(b) $ 1,138 $ 1,491 $ 1,834
THREE MONTHS ENDED: June 30,
2014
March 31,
2014
June 30,
2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,352 $ 1,291
$ 1,281 Changes in assets and liabilities (83 ) 323 85 Interest
expense, net of unrealized gains on derivatives 58 55 53 Natural
gas, oil and NGL derivative gains (losses), net (213 ) (382 ) 598
Cash payments on natural gas, oil and NGL derivative settlements,
net 150 168 (22 ) Share-based compensation (20 ) (20 ) (24 )
Restructuring and other termination costs (33 ) 9 1 Impairments of
fixed assets and other (39 ) (12 ) (231 ) Net gains on sales of
fixed assets 93 23 109 Earnings (losses) on investments (24 ) (21 )
22 Net gains (losses) on sales of investments — 67 (10 ) Losses on
purchases of debt and extinguishment of other financing (61 ) — (17
) Other items (42 ) (10 ) (11 )
EBITDA(b) $ 1,138
$ 1,491 $ 1,834
(a) 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 that is used to internally fund
exploration and development activities and to service
debt. This measure is widely used by investors and
rating agencies in the valuation, comparison, rating and investment
recommendations of companies within the 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.
(b) Ebitda represents net income before
interest expense, income taxes, and depreciation, depletion and
amortization expense. Ebitda is presented as a
supplemental financial measurement in the evaluation of our
business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital
requirements. This measure is widely used by investors
and rating agencies in the valuation, comparison, rating and
investment recommendations of companies. Ebitda is also a financial
measurement that, with certain negotiated adjustments, is reported
to our lenders pursuant to our bank credit agreements and is used
in the financial covenants in our bank credit
agreements. Ebitda is not a measure of financial
performance under GAAP. Accordingly, it should not be
considered as a substitute for net income, income from operations
or cash flow provided by operating activities prepared in
accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW
AND EBITDA
($ in millions)
(unaudited)
SIX MONTHS
ENDED: June 30,
2014
June 30,
2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 2,643
$ 2,205 Changes in assets and liabilities 240 341
OPERATING CASH FLOW(a) $ 2,883 $ 2,546
SIX
MONTHS ENDED: June 30,
2014
June 30,
2013
NET INCOME $ 696 $ 728 Interest expense 66 124 Income
tax expense 421 446 Depreciation and amortization of other assets
157 154 Natural gas, oil and NGL depreciation, depletion and
amortization 1,288 1,293
EBITDA(b) $
2,628 $ 2,745
SIX MONTHS ENDED: June
30,
2014
June 30,
2013
CASH PROVIDED BY OPERATING ACTIVITIES $ 2,643 $ 2,205
Changes in assets and liabilities 240 341 Interest expense, net of
unrealized gains (losses) on derivatives 113 67 Natural gas, oil
and NGL derivative gains (losses), net (595 ) 470 Cash payments on
natural gas, oil and NGL derivative settlements, net 318 (41 )
Share-based compensation (40 ) (56 ) Restructuring and other
termination costs (24 ) (104 ) Impairments of fixed assets and
other (51 ) (258 ) Net gains on sales of fixed assets 115 158
Losses on investments (45 ) (7 ) Net gains (losses) on sales of
investments 67 (10 ) Losses on purchases of debt and extinguishment
of other financing (61 ) (17 ) Other items (52 ) (3 )
EBITDA(b) $ 2,628 $ 2,745
(a) 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.
(b) Ebitda represents net
income before interest expense, income taxes, and depreciation,
depletion and amortization expense. Ebitda is presented
as a supplemental financial measurement in the evaluation of our
business. We believe that it provides additional
information regarding our ability to meet our future debt service,
capital expenditures and working capital
requirements. This measure is widely used by investors
and rating agencies in the valuation, comparison, rating and
investment recommendations of companies. Ebitda is also a financial
measurement that, with certain negotiated adjustments, is reported
to our lenders pursuant to our bank credit agreements and is used
in the financial covenants in our bank credit
agreements. Ebitda is not a measure of financial
performance under GAAP. Accordingly, it should not be
considered as a substitute for net income, income from operations
or cash flow provided by operating activities prepared in
accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED
EBITDA
($ in millions)
(unaudited)
THREE MONTHS ENDED: June 30,
2014
March 31,
2014
June 30,
2013
EBITDA $ 1,138 $ 1,491 $ 1,834
Adjustments: Unrealized (gains) losses on natural gas, oil
and NGL derivatives — 144 (576 ) Restructuring and other
termination costs 33 (7 ) 7 Impairments of fixed assets and other
40 20 231 Net gains on sales of fixed assets (93 ) (23 ) (109 )
Impairments of investments 5 — — Net (gains) losses on sales of
investments — (67 ) 10 Losses on purchases of debt and
extinguishment of other financing 195 — 70 Net income attributable
to noncontrolling
interests
(39 ) (41 ) (45 ) Other (2 ) (2 ) 2
Adjusted
EBITDA(a) $ 1,277 $ 1,515 $ 1,424
SIX MONTHS
ENDED: June 30,
2014
June 30,
2013
EBITDA $ 2,628 $ 2,745
Adjustments:
Unrealized (gains) losses on natural gas, oil and NGL derivatives
144 (429 ) Restructuring and other termination costs 26 140
Impairments of fixed assets and other 60 258 Net gains on sales of
fixed assets (115 ) (158 ) Impairment of investments 5 10 Net
(gains) losses on sales of investments (67 ) 10 Losses on purchases
of debt and extinguishment of other financing 195 70 Net income
attributable to noncontrolling
interests
(80 ) (89 ) Other (4 ) 1
Adjusted
EBITDA(a) $ 2,792 $ 2,558
(a) 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.
SCHEDULE "A”
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT’S OUTLOOK AS OF AUGUST 6,
2014
Chesapeake periodically provides
management guidance on certain factors that affect the company’s
future financial performance. The primary changes from
the company’s May 16, 2014 Outlook are in italicized bold
below.
Year Ending12/31/2014
Production Growth (adjusted for asset sales)(a): Liquids: 29 – 33%
Oil 11 – 15% NGL(b) 63 – 68% Natural gas 4 – 6% Total Adjusted
Production Growth 9 – 12% Daily Equivalent Rate - mboe
685 – 705 NYMEX Price(c) (for calculation of realized
hedging effects only): Oil - $/bbl
$97.92 Natural gas -
$/mcf
$4.43 Estimated Realized Hedging Effects(d) (based on
assumed NYMEX prices above): Oil - $/bbl
($7.84) Natural gas
- $/mcf
($0.21) Estimated
Basis/Gathering/Marketing/Transportation Differentials to NYMEX
Prices: Oil - $/bbl
$5.00 – 7.00 NGL - $/bbl
$72.00 –
76.00 Natural gas - $/mcf
$1.75 – 1.85 Operating Costs
per Boe of Projected Production: Production expense $4.25 – 4.75
Production taxes
$0.90 – 1.00 General and administrative(e)
$1.20 – 1.30 Share-based compensation (noncash) $0.15 – 0.20
DD&A of natural gas and liquids assets $10.00 – 11.00
Depreciation of other assets $0.90 – 1.00 Interest expense(f) $0.65
– 0.75 Other ($ millions): Marketing, gathering and compression net
margin(g) $50 – 75 Net income attributable to noncontrolling
interests and other(h)
($100 – 130) Book Tax Rate 37.5%
Weighted Average Shares Outstanding (in millions): Basic 657 – 661
Diluted
775 – 779 Operating Cash Flow before Changes in
Assets and Liabilities ($ in millions) (i)(j)
$5,350 – 5,550
Total Capital Expenditures ($ in millions) $5,000 – 5,400
Capitalized interest, dividends and distributions ($ in millions)
$1,070 – 1,120
a) Growth ranges based on 2013
production of 604 mboe/day adjusted for asset sales in 2013 and
2014.
b) Assumes ethane recovery in
the Utica and southern Marcellus to fulfill Chesapeake’s pipeline
commitments, no ethane recovery in the Rockies and partial ethane
recovery in the Mid-Continent and Eagle Ford.
c) NYMEX natural gas and oil
prices have been updated for actual contract prices through July
and June, respectively.
d) Includes expected
settlements for commodity derivatives adjusted for option
premiums. For derivatives closed early, settlements are
reflected in the period of original contract expiration.
e) Excludes expenses associated
with share-based compensation and restructuring and other
termination costs.
f) Excludes unrealized gains
(losses) on interest rate derivatives.
g) Includes revenue and
operating expenses and excludes depreciation and amortization of
other assets
h) Net income attributable to
noncontrolling interests of Chesapeake Granite Wash Trust, CHK
Utica, L.L.C. and CHK Cleveland Tonkawa, L.L.C. CHK
Utica became wholly owned on July 29, 2014 when the company
purchased CHK Utica preferred shares held by third parties.
i) A non-GAAP financial
measure. We are unable to provide reconciliation to
projected cash provided by operating activities, the most
comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
j) Assumes NYMEX prices on open
contracts of $95.00 per bbl and $4.00 per mcf and production growth
ranges as shown above.
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative
transactions in order to mitigate a portion of its exposure to
adverse changes in market prices. Please see the quarterly reports
on Form 10-Q and annual reports on Form 10-K filed by Chesapeake
with the SEC for detailed information about derivative instruments
the company uses, its quarter-end and year-end derivative positions
and accounting for natural gas, oil and NGL derivatives.
As of July 31, 2014, the company had downside protection on
approximately 69% of its remaining projected 2014 natural gas
production at an average price of $4.12 per thousand cubic feet of
natural gas. Approximately 65% of the company's remaining projected
2014 oil production had downside protection at an average price of
$94.25 per bbl.
The company’s natural gas hedging positions as of July 31, 2014
were as follows:
Open Natural Gas Swaps; Gains (Losses)
from Closed
Natural Gas Trades and Call Option
Premiums
Open
Swaps
(bcf)
Avg. NYMEX
Price of
Open Swaps
Total Gains (Losses) from
Closed Trades and Premiums for Call
Options ($ in millions)
Q3 2014 112 $ 4.09 $ (15 ) Q4 2014 112
4.09
(21 ) Total Q3 - Q4 2014 224 $ 4.09
$ (36 ) Total 2015 68 $ 4.63
$ (131 ) Total 2016 – 2022 0 - $ (187 )
Natural Gas Three-Way Collars
Open
Collars
(bcf)
Avg. NYMEX
Sold Put Price
Avg. NYMEX
Bought Put Price
Avg. NYMEX
Ceiling Price
Q3 2014 57 $ 3.55 $ 4.09 $ 4.38 Q4 2014 71 3.49
4.11 4.37 Total Q3 - Q4 2014 128
$ 3.52 $ 4.10 $ 4.37 Total 2015
207 $ 3.37 $ 4.29 $ 4.51
Natural Gas Collars
Open Collars
(bcf)
Avg. NYMEXBought Put Price Avg. NYMEX
Bought Put Price
Q3 2014
11 $ 4.50 $ 5.24 Q4 2014
11 4.50 5.24 Total
Q3 - Q4 2014
22 $ 4.50
$ 5.24
Natural Gas Written Call
Options
Call Options
(bcf)
Avg. NYMEX
Strike Price
Total 2016 – 2020 193 $ 9.92
Natural Gas Basis Protection
Swaps
Volume (bcf)
Avg. NYMEX minus Q3 2014 46 $ (0.53 ) Q4 2014
25 (0.62 ) Total Q3 - Q4 2014
71 $ (0.56 ) Total 2015
38 $ (0.48 ) Total 2016 - 2022
8 $ (1.02 )
The company’s crude oil hedging positions as of July 31, 2014
were as follows:
Open Crude Oil Swaps; Gains (Losses)
from Closed
Crude Oil Trades and Call Option
Premiums
Open
Swaps
(mbbls)
Avg. NYMEX
Price of
Open Swaps
Total Gains (Losses) from
Closed Trades and Premiums for Call
Options ($ in millions)
Q3 2014 7,241 $ 94.28 $ (48 ) Q4 2014 7,197 94.22
(49 ) Total Q3 - Q4 2014 14,438 $ 94.25
$ (97 ) Total 2015
12,457
$ 94.58 $ 239
Total 2016 – 2022 0 — $ 117
Crude Oil Written Call Options
Call Options
(mbbls)
Avg. NYMEX
Strike Price
Q3 2014 626 $ 83.53 Q4 2014 626 83.53 Total Q3 - Q4
2014 1,252 $ 83.53 Total 2015 13,434 $
91.89 Total 2016 – 2017 24,220 $ 100.07
Crude Oil Basis Protection
Swaps
Volume (mbbls) Avg. NYMEX plus Q3 2014
92 $ 6.00 Q4 2014 92 6.00 Total Q3 - Q4 2014
184 $ 6.00
Chesapeake Energy CorporationInvestor
Relations:Gary T. Clark, CFA, 405-935-8870ir@chk.comorMedia
Relations:Gordon Pennoyer, 405-935-8878media@chk.com
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