Chesapeake Energy Corporation (NYSE:CHK) today reported financial and
operational results for the 2013 second quarter. Key information related
to the quarter is as follows:
-
Adjusted net income per fully diluted share of $0.51, compared
to $0.06 in the 2012 second quarter
-
Adjusted ebitda of $1.424 billion increases 77% year over year
-
Daily oil production rises 44% year over year to 116,000 bbls
per day
-
Full-year 2013 oil production outlook increases by 1 million
barrels to 38 – 40 million barrels, a 22 to 28% increase year over year
-
Total daily production increases 7% year over year to 4.1 bcfe
per day
-
Conference call at 9:00 am EDT today; dial-in 913-312-0968,
passcode 3533928
Chesapeake reported net income available to common stockholders of $457
million, or $0.66 per fully diluted share. These results include the
effects of the following after-tax items:
-
noncash unrealized mark-to-market gains of $325 million from the
company’s derivative instruments;
-
a noncash charge of $143 million for the impairment of certain of the
company’s property and equipment, consisting primarily of noncore real
estate;
-
a net gain of $68 million on sales of certain of the company’s
property and equipment, consisting primarily of midstream assets;
-
a charge of $44 million on the repurchase of $1.894 billion aggregate
principal amount of the company’s senior notes; and
-
a $69 million premium paid over the carrying value on the purchase of
preferred shares of a company subsidiary.
Adjusting for these and other items not typically included in earnings
estimates by securities analysts, Chesapeake reported adjusted net
income available to common stockholders of $334 million, or $0.51 per
fully diluted share, which compares to adjusted net income available to
common stockholders of $3 million, or $0.06 per fully diluted share, in
the 2012 second quarter.
The company reported adjusted ebitda of $1.424 billion, an increase of
77% year over year. Operating cash flow, which is cash flow provided by
operating activities before changes in assets and liabilities, was $1.370
billion, an increase of 53% year over year. Additional
definitions and reconciliations to comparable financial measures
calculated in accordance with generally accepted accounting principles
of adjusted net income available to common stockholders, operating cash
flow, ebitda and adjusted ebitda are provided on pages 12 - 16 of this
release.
Doug Lawler, Chesapeake’s Chief Executive Officer, said, “Chesapeake
reported a strong quarter operationally and financially. I am very
excited and energized by what I have seen during my first six weeks with
the company. Chesapeake has an exceptionally broad and deep asset base,
which offers tremendous opportunity for value creation. A comprehensive
companywide review of our capital allocation and other processes is
underway and I believe these initiatives will result in substantial
further improvement in both near-term and long-term capital efficiency
and returns.”
2013 Second Quarter Total Production Increases 7% Year over Year to
4.1 Bcfe per Day; Oil Production Increases 44% Year over Year to 116,000
Bbls per Day
Chesapeake’s daily production for the 2013 second quarter averaged
approximately 4.1 billion cubic feet of natural gas equivalent (bcfe),
an increase of 7% from the 2012 second quarter and an increase of 2%
from the 2013 first quarter. The company’s average daily production
consisted of approximately 3.1 billion cubic feet (bcf) of natural gas
and approximately 168,000 barrels (bbls) of liquids, comprised of
approximately 116,000 bbls of oil and approximately 52,000 bbls of
natural gas liquids (NGL).
During the 2013 second quarter, average daily oil production increased
44% year over year and 12% sequentially, and average daily NGL
production increased 5% year over year and decreased 4% sequentially.
The sequential NGL volume decrease was primarily the result of increased
ethane rejection during the second quarter. Liquids accounted for 25% of
total production during the 2013 second quarter, up from 21% during the
2012 second quarter.
Steve Dixon, Chesapeake’s Chief Operating Officer, commented, “We are
raising our full-year 2013 oil production guidance by 1 million barrels
(mmbbls) to 38 – 40 mmbbls, representing a growth rate of 22 to 28% year
over year, due to good well performance, an accelerated pace of well
completions in the Eagle Ford Shale and timing of asset sales. We are
also reducing our 2013 NGL production guidance by 2 mmbbls to 21 – 23
mmbbls to reflect ethane rejection that occurred during the second
quarter and thus far in the third quarter as well as anticipated delays
associated with third-party gathering, compression and processing in the
Utica Shale.”
Capital Spending and Cost Overview
During the 2013 second quarter, Chesapeake operated an average of 76
rigs, a decrease of seven rigs compared to the 2013 first quarter, and
invested approximately $1.6 billion in drilling and completion costs.
This brings drilling and completion costs for the first half of 2013 to
approximately $3.1 billion. Chesapeake spud a total of 312 wells and
completed 410 wells during the 2013 second quarter, compared to 294
wells spud and 352 wells completed during the 2013 first quarter.
During the second half of 2013, Chesapeake plans to operate an average
of 64 rigs compared to an average of 81 rigs during the first half of
the year. The company also plans to complete approximately 20% fewer
wells in the second half of 2013 compared to the first half of the year.
Based on these planned activity levels, the company is reducing its 2013
full-year guidance for drilling and completion costs from a range of
$5.75 – $6.25 billion to $5.7 – $6.0 billion.
Net expenditures for the acquisition of unproved properties were
approximately $55 million during the 2013 second quarter, bringing 2013
first-half net expenditures for the acquisition of unproved properties
to approximately $100 million. The company continues to track below its
budgeted leasehold expenditures for the year and is lowering its 2013
full-year leasehold expenditure guidance from $400 million to $300 –
$350 million. Other capital expenditures were approximately $190 million
during the 2013 second quarter and $535 million during the first half of
2013.
Average production expenses during the 2013 second quarter were $0.78
per thousand cubic feet of natural gas equivalent (mcfe), a decrease of
20% year over year. General and administrative (G&A) expenses (excluding
stock-based compensation) were $0.25 per mcfe, a decrease of 36% year
over year. To reflect improvements in cost control, Chesapeake is
reducing its 2013 per unit G&A expense guidance range by $0.05 to $0.25
– $0.30 per mcfe.
A complete summary of the company’s guidance for 2013 is provided in the
Outlook dated August 1, 2013 which is attached to this release as
Schedule “A” beginning on Page 17. This updates information previously
provided in the Outlook dated May 1, 2013.
Asset Sales Update
Chesapeake continues to make significant progress in selling noncore
assets. During the first half of 2013, the company received proceeds of
approximately $2.4 billion from asset sales. During the 2013 third
quarter to date, the company has completed the sales of additional
assets in the Haynesville Shale and Eagle Ford Shale to subsidiaries of
EXCO Resources, Inc. (NYSE:XCO) for total consideration of approximately
$1 billion (inclusive of approximately $100 million that is subject to
customary post-closing contingencies) and expects to complete today the
sale of midstream assets in the Mississippi Lime play to SemGroup
Corporation (NYSE:SEMG) for total consideration of approximately $300
million. Chesapeake is also pursuing several other transactions of
varying sizes that may reach completion before the end of 2013.
Operational Update
The company continues to achieve strong operational results in its most
active plays, as highlighted below.
Eagle Ford Shale (South Texas): In
the Eagle Ford Shale play, Chesapeake connected 140 wells to sales
during the 2013 second quarter, which was substantially more than the
111 wells connected during the 2013 first quarter. Net production during
the 2013 second quarter averaged approximately 85,000 barrels of oil
equivalent (boe) per day (190,000 gross operated boe per day). This
represents an increase of 135% year over year and 14% sequentially. The
average peak daily production rate of the 140 wells that commenced first
production during the 2013 second quarter was approximately 900 boe per
day. Approximately 66% of the company’s Eagle Ford production during the
2013 second quarter was oil, 14% was NGL and 20% was natural gas.
Chesapeake is currently operating 15 rigs in the Eagle Ford and, due to
reduced cycle times and the sale discussed above, plans to reduce its
operated rig count to 10 by the end of 2013. Average spud-to-spud cycle
time during the quarter was 16 days, down from 21 days year over year.
As of June 30, 2013, Chesapeake had drilled a total of 963 wells in the
Eagle Ford, which included 795 producing wells, 24 additional wells
waiting on pipeline connection and 144 wells in various stages of
completion.
Utica Shale (eastern Ohio, Pennsylvania, West
Virginia): Net production from the Utica Shale play
averaged approximately 85 million cubic feet of natural gas equivalent
(mmcfe) per day during the 2013 second quarter, an increase of 48%
sequentially from the 2013 first quarter. The average peak daily
production rate of the 42 wells that commenced first production in the
Utica during the 2013 second quarter was approximately 6.6 mmcfe per day.
Chesapeake is currently operating 11 rigs in the Utica, which it plans
to reduce to 10 rigs by year end. Average spud-to-spud cycle time during
the quarter was 18 days, down from 26 days a year ago. As of June 30,
2013, Chesapeake had drilled a total of 321 wells in the Utica, which
included 106 producing wells, 93 additional wells waiting on pipeline
connection and 122 wells in various stages of completion.
Greater Anadarko Basin (Oklahoma, Texas
Panhandle, southern Kansas): Chesapeake continues to
generate steady liquids production growth in the Greater Anadarko Basin
primarily from five plays: the Mississippi Lime, Granite Wash,
Cleveland, Tonkawa and Hogshooter. Aggregate net production from these
plays during the 2013 second quarter averaged 126,000 boe per day
(192,000 gross operated boe per day), an increase of 43% year over year
and 11% sequentially. The average peak daily production rate of the 123
wells that commenced first production in the Greater Anadarko Basin
during the 2013 second quarter was approximately 800 boe per day.
Approximately 38% of the company’s Greater Anadarko Basin production
during the 2013 second quarter was oil, 18% was NGL and 44% was natural
gas.
Chesapeake is currently operating 26 rigs across these plays, which it
plans to reduce to 19 rigs by year end. As of June 30, 2013, the company
had an inventory of 58 drilled but uncompleted and/or unconnected wells
in the Greater Anadarko Basin.
Marcellus Shale (Pennsylvania, West Virginia):
The company’s production from the Marcellus Shale continued to grow
during the 2013 second quarter, benefiting from the availability of
downstream takeaway capacity and the completion of wells in backlog.
Chesapeake connected 131 wells to sales during the 2013 second quarter,
which was substantially more than the 52 wells connected during the 2013
first quarter. Approximately 2% of the company’s Marcellus production
during the 2013 second quarter was oil, 3% was NGL and 95% was natural
gas.
During the 2013 second quarter, Chesapeake’s average daily net
production in the northern dry- gas portion of the Marcellus was
approximately 780 mmcfe per day (1,810 gross operated mmcfe per day), an
increase of 58% year over year and 11% sequentially. The average peak
daily production rate of the 79 wells that commenced first production
during the 2013 second quarter in the northern Marcellus was
approximately 9 mmcfe per day.
Chesapeake is currently operating five rigs in the northern dry-gas
portion of the play and anticipates maintaining this activity level for
the remainder of 2013. Average spud-to-spud cycle time during the 2013
second quarter was 29 days, down from 31 days a year ago. As of June 30,
2013, Chesapeake had an inventory of 144 drilled but uncompleted and/or
unconnected wells in the northern Marcellus.
During the 2013 second quarter, Chesapeake’s average daily net
production in the southern wet-gas portion of the Marcellus was
approximately 208 mmcfe per day (355 gross operated mmcfe per day), an
increase of 56% year over year and 23% sequentially. The average peak
daily production rate of the 52 wells that commenced first production
during the 2013 second quarter in the southern Marcellus was
approximately 6.5 mmcfe per day.
Chesapeake is currently operating three rigs in the southern wet-gas
portion of the play, which it plans to reduce to two rigs by year end.
Average spud-to-spud cycle time during the 2013 second quarter was 21
days, down from 33 days a year ago. As of June 30, 2013, Chesapeake had
an inventory of 76 drilled but uncompleted and/or unconnected wells in
the southern Marcellus.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational
results during the 2013 second quarter and compares them to results
during the 2013 first quarter and the 2012 second quarter.
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Three Months Ended
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6/30/13
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3/31/13
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6/30/12
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Natural gas equivalent production (in bcfe)
|
|
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369
|
|
|
358
|
|
|
347
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|
Natural gas equivalent realized price ($/mcfe)(a) |
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4.96
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|
|
4.46
|
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3.77
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Oil production (in mbbls)
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10,539
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9,283
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7,325
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Average realized oil price ($/bbl)(a) |
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93.81
|
|
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94.85
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91.58
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Oil as % of total production
|
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17
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16
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13
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NGL production (in mbbls)
|
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4,751
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4,882
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4,525
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Average realized NGL price ($/bbl)(a) |
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24.22
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28.25
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25.94
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NGL as % of total production
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8
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8
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8
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Liquids as % of realized revenue(b) |
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60
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64
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60
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Liquids as % of unhedged revenue(b) |
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58
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64
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70
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Natural gas production (in bcf)
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278
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273
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275
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Average realized natural gas price ($/mcf)(a) |
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2.62
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2.13
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1.88
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Natural gas as % of total production
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75
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76
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79
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Natural gas as % of realized revenue
|
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40
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36
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40
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Natural gas as % of unhedged revenue
|
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42
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36
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30
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Production expenses ($/mcfe)
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(0.78
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)
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(0.86
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)
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(0.97
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)
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Production taxes ($/mcfe)
|
|
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(0.16
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)
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(0.15
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)
|
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(0.12
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)
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General and administrative costs ($/mcfe)(c) |
|
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(0.25
|
)
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(0.25
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)
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(0.39
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)
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Stock-based compensation ($/mcfe)
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(0.04
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)
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(0.06
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)
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(0.06
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)
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DD&A of natural gas and liquids properties ($/mcfe)
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(1.75
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)
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(1.81
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)
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(1.70
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)
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D&A of other assets ($/mcfe)
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(0.21
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)
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(0.22
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)
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(0.24
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)
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Interest expense ($/mcfe)(a) |
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(0.14
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)
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(0.04
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)
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(0.06
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)
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Marketing, gathering and compression net margin ($ in millions) (d) |
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29
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36
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17
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Oilfield services net margin ($ in millions) (d) |
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35
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35
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50
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Operating cash flow ($ in millions)(e) |
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1,370
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1,176
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|
895
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Operating cash flow ($/mcfe)
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3.71
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|
|
3.28
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2.58
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Adjusted ebitda ($ in millions)(f) |
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1,424
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1,134
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|
803
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Adjusted ebitda ($/mcfe)
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3.86
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|
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3.17
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2.32
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Net income available to common stockholders ($ in millions)
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457
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15
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929
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Earnings per share – diluted ($)
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0.66
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0.02
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|
|
1.29
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Adjusted net income available to common stockholders ($ in millions)(g) |
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334
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183
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3
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Adjusted earnings per share – diluted ($)
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0.51
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0.30
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0.06
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(a) Includes the effects of realized gains (losses)
from hedging, but excludes the effects of unrealized gains
(losses) from hedging.
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(b) “Liquids” includes both oil and NGL.
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(c) Excludes expenses associated with noncash
stock-based compensation.
|
(d) Includes revenue and operating costs and excludes
depreciation and amortization of other assets.
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(e) Defined as cash flow provided by operating
activities before changes in assets and liabilities.
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(f) 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 16.
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(g) Defined as net income available to common
stockholders, as adjusted to remove the effects of certain items
detailed on Page 12.
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2013 Second Quarter Financial and Operational Results Conference Call
Information
A conference call to discuss this release has been scheduled for
Thursday, August 1, 2013, at 9:00 am EDT. The telephone number to access
the conference call is 913-312-0968 or toll-free 888-215-6895.
The passcode for the call is 3533928. 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 Thursday,
August 1, 2013, and will run through 2:00 pm EDT on Thursday, August 15,
2013. The number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is 3533928.
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 company’s
website. The webcast of the conference will be available on the
company’s website for one year.
Chesapeake Energy Corporation (NYSE:CHK) is the second-largest
producer of natural gas, a Top 11 producer of oil and natural gas
liquids and the most active driller of new wells in the U.S.
Headquartered in Oklahoma City, the company's operations are focused on
discovering and developing unconventional natural gas and oil fields
onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford,
Utica, Granite Wash/Hogshooter, Cleveland, Tonkawa, Mississippi Lime and
Niobrara unconventional liquids plays and in the Marcellus,
Haynesville/Bossier and Barnett unconventional natural gas shale plays.
The company also owns substantial marketing and oilfield services
businesses through its subsidiaries Chesapeake Energy Marketing, Inc.
and Chesapeake Oilfield Operating, L.L.C. 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 Outlooks 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 that give our current expectations or
forecasts of future events. They include production forecasts,
estimates of operating costs, planned development drilling, expected
capital expenditures, anticipated asset sales, projected cash flow and
liquidity, 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 assumptions or by known or unknown risks and
uncertainties.
Factors that could cause actual results to differ materially from
expected results are described under “Risk Factors” in Item 1A of our
2012 annual report on Form 10-K filed with the U.S. Securities and
Exchange Commission on March 1, 2013. 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; current
worldwide economic uncertainty which may have 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; losses possible from
pending or future litigation and regulatory investigations; cyber
attacks adversely impacting our operations; and the loss of key
operational personnel or inability to maintain our corporate culture.
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. We do not have binding agreements for all of our
planned 2013 asset sales. Our ability to consummate each of these
transactions is subject to changes in market conditions and other
factors. 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 this information.
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CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share and unit data)
(unaudited)
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June 30,
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June 30,
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THREE MONTHS ENDED:
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2013
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2012
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$
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$/mcfe
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$
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$/mcfe
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REVENUES:
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Natural gas, oil and NGL
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2,406
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6.51
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2,117
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6.11
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Marketing, gathering and compression
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2,057
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5.57
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1,113
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|
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3.21
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Oilfield services
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212
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0.58
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159
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0.46
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Total Revenues
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4,675
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|
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12.66
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3,389
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9.78
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OPERATING EXPENSES:
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|
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Natural gas, oil and NGL production
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|
|
288
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|
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0.78
|
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|
|
335
|
|
|
|
0.97
|
|
Production taxes
|
|
|
59
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|
|
|
0.16
|
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|
|
41
|
|
|
|
0.12
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|
Marketing, gathering and compression
|
|
|
2,028
|
|
|
|
5.49
|
|
|
|
1,096
|
|
|
|
3.16
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Oilfield services
|
|
|
177
|
|
|
|
0.48
|
|
|
|
109
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0.31
|
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General and administrative
|
|
|
106
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|
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0.29
|
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|
155
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0.45
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Employee retirement and other termination benefits
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7
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|
0.02
|
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|
|
1
|
|
|
|
0.00
|
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Natural gas, oil and NGL depreciation, depletion and
amortization
|
|
|
645
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|
1.75
|
|
|
|
588
|
|
|
|
1.70
|
|
Depreciation and amortization of other assets
|
|
|
76
|
|
|
|
0.21
|
|
|
|
83
|
|
|
|
0.24
|
|
Impairments of fixed assets and other
|
|
|
231
|
|
|
|
0.62
|
|
|
|
243
|
|
|
|
0.70
|
|
Net gains on sales of fixed assets
|
|
|
(109
|
)
|
|
|
(0.30
|
)
|
|
|
—
|
|
|
|
—
|
|
Total Operating Expenses
|
|
|
3,508
|
|
|
|
9.50
|
|
|
|
2,651
|
|
|
|
7.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM OPERATIONS
|
|
|
1,167
|
|
|
|
3.16
|
|
|
|
738
|
|
|
|
2.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(104
|
)
|
|
|
(0.28
|
)
|
|
|
(14
|
)
|
|
|
(0.04
|
)
|
Earnings (losses) on investments
|
|
|
23
|
|
|
|
0.06
|
|
|
|
(59
|
)
|
|
|
(0.17
|
)
|
Gains (losses) on sales of investments
|
|
|
(10
|
)
|
|
|
(0.03
|
)
|
|
|
1,030
|
|
|
|
2.97
|
|
Losses on purchases of debt
|
|
|
(70
|
)
|
|
|
(0.19
|
)
|
|
|
—
|
|
|
|
—
|
|
Other income
|
|
|
3
|
|
|
|
0.01
|
|
|
|
5
|
|
|
|
0.01
|
|
Total Other Income (Expense)
|
|
|
(158
|
)
|
|
|
(0.43
|
)
|
|
|
962
|
|
|
|
2.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
1,009
|
|
|
|
2.73
|
|
|
|
1,700
|
|
|
|
4.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes
|
|
|
2
|
|
|
|
0.01
|
|
|
|
2
|
|
|
|
—
|
|
Deferred income taxes
|
|
|
382
|
|
|
|
1.03
|
|
|
|
661
|
|
|
|
1.91
|
|
Total Income Tax Expense
|
|
|
384
|
|
|
|
1.04
|
|
|
|
663
|
|
|
|
1.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
625
|
|
|
|
1.69
|
|
|
|
1,037
|
|
|
|
2.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interests
|
|
|
(45
|
)
|
|
|
(0.12
|
)
|
|
|
(65
|
)
|
|
|
(0.19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME ATTRIBUTABLE TO CHESAPEAKE
|
|
|
580
|
|
|
|
1.57
|
|
|
|
972
|
|
|
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
(43
|
)
|
|
|
(0.11
|
)
|
|
|
(43
|
)
|
|
|
(0.12
|
)
|
Earnings allocated to participating securities
|
|
|
(11
|
)
|
|
|
(0.03
|
)
|
|
|
—
|
|
|
|
—
|
|
Premium on purchase of preferred shares of a subsidiary
|
|
|
(69
|
)
|
|
|
(0.19
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS
|
|
|
457
|
|
|
|
1.24
|
|
|
|
929
|
|
|
|
2.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.70
|
|
|
|
|
|
|
$
|
1.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.66
|
|
|
|
|
|
|
$
|
1.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
653
|
|
|
|
|
|
|
|
642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
760
|
|
|
|
|
|
|
|
751
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share and unit data)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
$
|
|
|
$/mcfe
|
|
|
$
|
|
$/mcfe
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and NGL
|
|
|
3,858
|
|
|
|
5.30
|
|
|
|
3,185
|
|
|
|
4.69
|
|
Marketing, gathering and compression
|
|
|
3,838
|
|
|
|
5.28
|
|
|
|
2,328
|
|
|
|
3.43
|
|
Oilfield services
|
|
|
402
|
|
|
|
0.55
|
|
|
|
294
|
|
|
|
0.43
|
|
Total Revenues
|
|
|
8,098
|
|
|
|
11.13
|
|
|
|
5,807
|
|
|
|
8.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, oil and NGL production
|
|
|
595
|
|
|
|
0.82
|
|
|
|
685
|
|
|
|
1.01
|
|
Production taxes
|
|
|
112
|
|
|
|
0.15
|
|
|
|
89
|
|
|
|
0.13
|
|
Marketing, gathering and compression
|
|
|
3,772
|
|
|
|
5.19
|
|
|
|
2,292
|
|
|
|
3.37
|
|
Oilfield services
|
|
|
332
|
|
|
|
0.46
|
|
|
|
205
|
|
|
|
0.30
|
|
General and administrative
|
|
|
216
|
|
|
|
0.30
|
|
|
|
291
|
|
|
|
0.43
|
|
Employee retirement and other termination benefits
|
|
|
140
|
|
|
|
0.19
|
|
|
|
1
|
|
|
|
—
|
|
Natural gas, oil and NGL depreciation, depletion and
amortization
|
|
|
1,293
|
|
|
|
1.78
|
|
|
|
1,094
|
|
|
|
1.61
|
|
Depreciation and amortization of other assets
|
|
|
154
|
|
|
|
0.21
|
|
|
|
166
|
|
|
|
0.25
|
|
Impairments of fixed assets and other
|
|
|
258
|
|
|
|
0.35
|
|
|
|
243
|
|
|
|
0.36
|
|
Net gains on sales of fixed assets
|
|
|
(158
|
)
|
|
|
(0.22
|
)
|
|
|
(2
|
)
|
|
|
—
|
|
Total Operating Expenses
|
|
|
6,714
|
|
|
|
9.23
|
|
|
|
5,064
|
|
|
|
7.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM OPERATIONS
|
|
|
1,384
|
|
|
|
1.90
|
|
|
|
743
|
|
|
|
1.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(124
|
)
|
|
|
(0.17
|
)
|
|
|
(26
|
)
|
|
|
(0.04
|
)
|
Losses on investments
|
|
|
(4
|
)
|
|
|
(0.01
|
)
|
|
|
(64
|
)
|
|
|
(0.09
|
)
|
Impairment of investment
|
|
|
(10
|
)
|
|
|
(0.01
|
)
|
|
|
—
|
|
|
|
—
|
|
Gains (losses) on sales of investments
|
|
|
(10
|
)
|
|
|
(0.01
|
)
|
|
|
1,030
|
|
|
|
1.51
|
|
Losses on purchases of debt
|
|
|
(70
|
)
|
|
|
(0.10
|
)
|
|
|
—
|
|
|
|
—
|
|
Other income
|
|
|
8
|
|
|
|
0.01
|
|
|
|
11
|
|
|
|
0.02
|
|
Total Other Income (Expense)
|
|
|
(210
|
)
|
|
|
(0.29
|
)
|
|
|
951
|
|
|
|
1.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
1,174
|
|
|
|
1.61
|
|
|
|
1,694
|
|
|
|
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current income taxes
|
|
|
3
|
|
|
|
—
|
|
|
|
2
|
|
|
|
—
|
|
Deferred income taxes
|
|
|
443
|
|
|
|
0.61
|
|
|
|
659
|
|
|
|
0.97
|
|
Total Income Tax Expense
|
|
|
446
|
|
|
|
0.61
|
|
|
|
661
|
|
|
|
0.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
728
|
|
|
|
1.00
|
|
|
|
1,033
|
|
|
|
1.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interests
|
|
|
(89
|
)
|
|
|
(0.12
|
)
|
|
|
(89
|
)
|
|
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME ATTRIBUTABLE TO CHESAPEAKE
|
|
|
639
|
|
|
|
0.88
|
|
|
|
944
|
|
|
|
1.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
(86
|
)
|
|
|
(0.12
|
)
|
|
|
(86
|
)
|
|
|
(0.13
|
)
|
Earnings allocated to participating securities
|
|
|
(11
|
)
|
|
|
(0.02
|
)
|
|
|
—
|
|
|
|
—
|
|
Premium on purchase of preferred shares of a subsidiary
|
|
|
(69
|
)
|
|
|
(0.09
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS
|
|
|
473
|
|
|
|
0.65
|
|
|
|
858
|
|
|
|
1.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.72
|
|
|
|
|
|
|
$
|
1.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.72
|
|
|
|
|
|
|
$
|
1.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
653
|
|
|
|
|
|
|
|
642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
653
|
|
|
|
|
|
|
|
752
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
677
|
|
|
$
|
287
|
Other current assets
|
|
|
2,915
|
|
|
|
2,661
|
Total Current Assets
|
|
|
3,592
|
|
|
|
2,948
|
|
|
|
|
|
|
|
|
Property and equipment (net)
|
|
|
37,349
|
|
|
|
37,167
|
Other assets
|
|
|
1,204
|
|
|
|
1,496
|
Total Assets
|
|
$
|
42,145
|
|
|
$
|
41,611
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
5,620
|
|
|
$
|
6,266
|
Long-term debt, net of discounts
|
|
|
13,057
|
|
|
|
12,157
|
Other long-term liabilities
|
|
|
2,004
|
|
|
|
2,485
|
Deferred income tax liabilities
|
|
|
3,260
|
|
|
|
2,807
|
Total Liabilities
|
|
|
23,941
|
|
|
|
23,715
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
3,062
|
|
|
|
3,062
|
Noncontrolling interests
|
|
|
2,169
|
|
|
|
2,327
|
Common stock and other stockholders’ equity
|
|
|
12,973
|
|
|
|
12,507
|
Total Equity
|
|
|
18,204
|
|
|
|
17,896
|
|
|
|
|
|
|
|
|
Total Liabilities and Equity
|
|
$
|
42,145
|
|
|
$
|
41,611
|
|
|
|
|
|
|
|
|
Common Shares Outstanding (in millions)
|
|
|
667
|
|
|
|
664
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Total debt, net of unrestricted cash
|
|
$
|
12,380
|
|
|
$
|
12,333
|
Preferred stock
|
|
|
3,062
|
|
|
|
3,062
|
Noncontrolling interests(a) |
|
|
2,169
|
|
|
|
2,327
|
Common stock and other stockholders’ equity
|
|
|
12,973
|
|
|
|
12,507
|
Total
|
|
$
|
30,584
|
|
|
$
|
30,229
|
Total debt to capitalization ratio
|
|
|
40%
|
|
|
|
41%
|
|
|
|
|
|
|
|
|
(a) Includes third-party ownership as follows:
|
|
|
|
|
|
|
|
CHK Cleveland Tonkawa, L.L.C.
|
|
$
|
1,015
|
|
|
$
|
1,015
|
CHK Utica, L.L.C.
|
|
|
807
|
|
|
|
950
|
Chesapeake Granite Wash Trust
|
|
|
338
|
|
|
|
356
|
Other
|
|
|
9
|
|
|
|
6
|
Total
|
|
$
|
2,169
|
|
|
$
|
2,327
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES
AND INTEREST EXPENSE
(unaudited)
|
|
|
|
|
|
|
Three Months Ended
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
June 30,
|
|
|
|
June 30,
|
|
|
|
June 30,
|
|
|
|
|
2013
|
|
|
|
2012
|
|
|
|
2013
|
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (bcf)
|
|
|
277.6
|
|
|
|
275.4
|
|
|
|
550.8
|
|
|
|
546.3
|
|
Oil (mmbbl)
|
|
|
10.5
|
|
|
|
7.3
|
|
|
|
19.8
|
|
|
|
13.3
|
|
NGL (mmbbl)
|
|
|
4.8
|
|
|
|
4.5
|
|
|
|
9.6
|
|
|
|
8.9
|
|
Natural gas equivalents (bcfe)
|
|
|
369.4
|
|
|
|
346.5
|
|
|
|
727.5
|
|
|
|
679.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, Oil and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
779
|
|
|
$
|
336
|
|
|
|
1,352
|
|
|
$
|
815
|
|
Natural gas derivatives – realized gains (losses)
|
|
|
(53
|
)
|
|
|
182
|
|
|
|
(45
|
)
|
|
|
339
|
|
Natural gas derivatives – unrealized gains (losses)
|
|
|
347
|
|
|
|
(164
|
)
|
|
|
68
|
|
|
|
(311
|
)
|
|
|
|
|
|
|
.
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Sales
|
|
|
1,073
|
|
|
|
354
|
|
|
|
1,375
|
|
|
|
843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
|
975
|
|
|
|
656
|
|
|
|
1,859
|
|
|
|
1,247
|
|
Oil derivatives – realized gains (losses)
|
|
|
14
|
|
|
|
15
|
|
|
|
10
|
|
|
|
(19
|
)
|
Oil derivatives – unrealized gains (losses)
|
|
|
229
|
|
|
|
955
|
|
|
|
361
|
|
|
|
817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil Sales
|
|
|
1,218
|
|
|
|
1,626
|
|
|
|
2,230
|
|
|
|
2,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL sales
|
|
|
115
|
|
|
|
120
|
|
|
|
253
|
|
|
|
272
|
|
NGL derivatives – realized gains (losses)
|
|
|
—
|
|
|
|
(2
|
)
|
|
|
—
|
|
|
|
(9
|
)
|
NGL derivatives – unrealized gains (losses)
|
|
|
—
|
|
|
|
19
|
|
|
|
—
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGL Sales
|
|
|
115
|
|
|
|
137
|
|
|
|
253
|
|
|
|
297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas, Oil and NGL Sales
|
|
$
|
2,406
|
|
|
$
|
2,117
|
|
$
|
|
3,858
|
|
|
$
|
3,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price –
excluding gains (losses) on derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($ per mcf)
|
|
$
|
2.81
|
|
|
$
|
1.22
|
|
$
|
|
2.45
|
|
|
$
|
1.49
|
|
Oil ($ per bbl)
|
|
$
|
92.53
|
|
|
$
|
89.49
|
|
$
|
|
93.79
|
|
|
$
|
93.49
|
|
NGL ($ per bbl)
|
|
$
|
24.22
|
|
|
$
|
26.40
|
|
$
|
|
26.26
|
|
|
$
|
30.68
|
|
Natural gas equivalent ($ per mcfe)
|
|
$
|
5.06
|
|
|
$
|
3.21
|
|
$
|
|
4.76
|
|
|
$
|
3.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price –
excluding unrealized gains (losses) on derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($ per mcf)
|
|
$
|
2.62
|
|
|
$
|
1.88
|
|
$
|
|
2.37
|
|
|
$
|
2.11
|
|
Oil ($ per bbl)
|
|
$
|
93.81
|
|
|
$
|
91.58
|
|
$
|
|
94.29
|
|
|
$
|
92.06
|
|
NGL ($ per bbl)
|
|
$
|
24.22
|
|
|
$
|
25.94
|
|
$
|
|
26.26
|
|
|
$
|
29.68
|
|
Natural gas equivalent ($ per mcfe)
|
|
$
|
4.96
|
|
|
$
|
3.77
|
|
$
|
|
4.71
|
|
|
$
|
3.89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense (Income) ($ in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest(a) |
|
$
|
54
|
|
|
$
|
21
|
|
$
|
|
70
|
|
|
$
|
28
|
|
Derivatives – realized (gains) losses
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(3
|
)
|
|
|
—
|
|
Derivatives – unrealized (gains) losses
|
|
|
51
|
|
|
|
(6
|
)
|
|
|
57
|
|
|
|
(2
|
)
|
Total Interest Expense
|
|
$
|
104
|
|
|
$
|
14
|
|
$
|
|
124
|
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Net of amounts capitalized.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED:
|
|
June 30,
|
|
|
June 30,
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Beginning cash
|
|
$
|
33
|
|
|
$
|
438
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
1,298
|
|
|
|
755
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Drilling and completion costs on proved and unproved properties(a)
|
|
|
(1,565
|
)
|
|
|
(2,516
|
)
|
Acquisition of proved and unproved properties(b)
|
|
|
(242
|
)
|
|
|
(529
|
)
|
Sale of proved and unproved properties
|
|
|
1,674
|
|
|
|
615
|
|
Geological and geophysical costs
|
|
|
(15
|
)
|
|
|
(42
|
)
|
Additions to other property and equipment
|
|
|
(176
|
)
|
|
|
(621
|
)
|
Proceeds from sales of other assets
|
|
|
258
|
|
|
|
31
|
|
Investments, net
|
|
|
101
|
|
|
|
1,945
|
|
Other
|
|
|
118
|
|
|
|
(154
|
)
|
Total cash provided by (used in) investing activities
|
|
|
153
|
|
|
|
(1,271
|
)
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
(807
|
)
|
|
|
1,109
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents classified as current
assets held for sale
|
|
|
—
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
644
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
Ending cash
|
|
$
|
677
|
|
|
$
|
1,024
|
|
|
|
|
|
|
|
|
|
|
(a) Includes capitalized interest of $31 million and $12 million
for the three months ended June 30, 2013 and 2012, respectively.
|
|
(b) Includes capitalized interest of $159 million and $152 million
for the three months ended June 30, 2013 and 2012, respectively.
|
|
|
SIX MONTHS ENDED:
|
|
June 30,
|
|
|
June 30,
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Beginning cash
|
|
$
|
287
|
|
|
$
|
351
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
2,222
|
|
|
|
1,029
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Drilling and completion costs on proved and unproved properties(c)
|
|
|
(3,131
|
)
|
|
|
(5,019
|
)
|
Acquisition of proved and unproved properties(d) |
|
|
(497
|
)
|
|
|
(1,646
|
)
|
Sale of proved and unproved properties
|
|
|
1,839
|
|
|
|
1,418
|
|
Geological and geophysical costs
|
|
|
(28
|
)
|
|
|
(113
|
)
|
Additions to other property and equipment
|
|
|
(506
|
)
|
|
|
(1,311
|
)
|
Proceeds from sales of other assets
|
|
|
459
|
|
|
|
79
|
|
Investments, net
|
|
|
98
|
|
|
|
1,872
|
|
Other
|
|
|
174
|
|
|
|
(201
|
)
|
Total cash provided by (used in) investing activities
|
|
|
(1,592
|
)
|
|
|
(4,921
|
)
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
(240
|
)
|
|
|
4,572
|
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents classified as current assets
held for sale
|
|
|
—
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
Change in cash and cash equivalents
|
|
|
390
|
|
|
|
673
|
|
|
|
|
|
|
|
|
|
|
Ending cash
|
|
$
|
677
|
|
|
$
|
1,024
|
|
|
|
|
|
|
|
|
|
|
(c) Includes capitalized interest of $46 million and $12 million
for the six months ended June 30, 2013 and 2012, respectively.
|
|
|
|
|
(d) Includes capitalized interest of $366 million and $314 million
for the six months ended June 30, 2013 and 2012, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
June 30,
|
|
THREE MONTHS ENDED:
|
|
2013
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
457
|
|
|
$
|
15
|
|
|
$
|
929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gains) losses on derivatives
|
|
|
(325
|
)
|
|
|
94
|
|
|
|
(490
|
)
|
Net gains on sales of fixed assets
|
|
|
(68
|
)
|
|
|
(30
|
)
|
|
|
—
|
|
Impairments of fixed assets and other
|
|
|
143
|
|
|
|
16
|
|
|
|
148
|
|
Impairment of investment
|
|
|
—
|
|
|
|
6
|
|
|
|
—
|
|
Employee retirement and other termination benefits
|
|
|
5
|
|
|
|
83
|
|
|
|
—
|
|
(Gains) losses on sales of investments
|
|
|
6
|
|
|
|
—
|
|
|
|
(584)
|
|
Losses on purchases of debt
|
|
|
44
|
|
|
|
—
|
|
|
|
—
|
|
Premium on purchase of preferred shares of a subsidiary
|
|
|
69
|
|
|
|
—
|
|
|
|
—
|
|
Other
|
|
|
3
|
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income available to common stockholders(a)
|
|
|
334
|
|
|
|
183
|
|
|
|
3
|
|
Preferred stock dividends
|
|
|
43
|
|
|
|
43
|
|
|
|
43
|
|
Earnings allocated to participating securities
|
|
|
11
|
|
|
|
—
|
|
|
|
—
|
|
Total adjusted net income
|
|
$
|
388
|
|
|
$
|
226
|
|
|
$
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fully diluted shares outstanding (in millions)(b) |
|
|
763
|
|
|
|
758
|
|
|
|
751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted earnings per share assuming dilution(a) |
|
$
|
0.51
|
|
|
$
|
0.30
|
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 under 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)
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
473
|
|
|
$
|
858
|
|
|
|
|
|
|
|
|
|
|
Adjustments, net of tax:
|
|
|
|
|
|
|
|
|
Unrealized gains on derivatives
|
|
|
(230
|
)
|
|
|
(331
|
)
|
Net gains on sales of fixed assets
|
|
|
(98
|
)
|
|
|
(1
|
)
|
Impairments of fixed assets and other
|
|
|
160
|
|
|
|
148
|
|
Impairment of investment
|
|
|
6
|
|
|
|
—
|
|
Employee retirement and other termination benefits
|
|
|
87
|
|
|
|
—
|
|
(Gains) losses on sales of investments
|
|
|
6
|
|
|
|
(584
|
)
|
Losses on purchases of debt
|
|
|
44
|
|
|
|
—
|
|
Premium on purchase of preferred shares of a subsidiary
|
|
|
69
|
|
|
|
—
|
|
Other
|
|
|
—
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income available to common stockholders(a)
|
|
|
517
|
|
|
|
97
|
|
Preferred stock dividends
|
|
|
86
|
|
|
|
86
|
|
Earnings allocated to participating securities
|
|
|
11
|
|
|
|
—
|
|
Total adjusted net income
|
|
$
|
614
|
|
|
$
|
183
|
|
|
|
|
|
|
|
|
|
|
Weighted average fully diluted shares outstanding (in millions)(b) |
|
|
764
|
|
|
|
752
|
|
|
|
|
|
|
|
|
|
|
Adjusted earnings per share assuming dilution(a) |
|
$
|
0.80
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
(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 GAAP earnings 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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
June 30,
|
|
THREE MONTHS ENDED:
|
|
2013
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
1,298
|
|
|
$
|
924
|
|
|
$
|
755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities
|
|
|
72
|
|
|
|
252
|
|
|
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING CASH FLOW(a) |
|
$
|
1,370
|
|
|
$
|
1,176
|
|
|
$
|
895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
June 30,
|
|
THREE MONTHS ENDED:
|
|
2013
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
625
|
|
|
$
|
102
|
|
|
$
|
1,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
104
|
|
|
|
21
|
|
|
|
14
|
|
Income tax expense
|
|
|
384
|
|
|
|
63
|
|
|
|
663
|
|
Depreciation and amortization of other assets
|
|
|
76
|
|
|
|
78
|
|
|
|
83
|
|
Natural gas, oil and NGL depreciation, depletion and
amortization
|
|
|
645
|
|
|
|
648
|
|
|
|
588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(b) |
|
$
|
1,834
|
|
|
$
|
912
|
|
|
$
|
2,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
June 30,
|
|
THREE MONTHS ENDED:
|
|
2013
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
1,298
|
|
|
$
|
924
|
|
|
$
|
755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities
|
|
|
72
|
|
|
|
252
|
|
|
|
140
|
|
Interest expense, net of unrealized gains (losses) on
derderivatives derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|
|
15
|
|
|
|
21
|
|
Unrealized gains (losses) on natural gas, oil and NGL
derivatives
|
|
|
576
|
|
|
|
(146
|
)
|
|
|
810
|
|
Net gains on sales of fixed assets
|
|
|
109
|
|
|
|
49
|
|
|
|
—
|
|
Impairments of fixed assets and other
|
|
|
(231
|
)
|
|
|
(27
|
)
|
|
|
(243
|
)
|
Employee retirement and other termination benefits
|
|
|
1
|
|
|
|
(105
|
)
|
|
|
—
|
|
Gains (losses) on sales of investments
|
|
|
(10
|
)
|
|
|
—
|
|
|
|
1,030
|
|
Earnings (losses) on investments
|
|
|
22
|
|
|
|
(29
|
)
|
|
|
(87
|
)
|
Impairment of investment
|
|
|
—
|
|
|
|
(10
|
)
|
|
|
—
|
|
Stock-based compensation
|
|
|
(24
|
)
|
|
|
(32
|
)
|
|
|
(26
|
)
|
Losses on purchases of debt
|
|
|
(17
|
)
|
|
|
—
|
|
|
|
—
|
|
Other items
|
|
|
(15
|
)
|
|
|
21
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA(b) |
|
$
|
1,834
|
|
|
$
|
912
|
|
|
$
|
2,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 (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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
2,222
|
|
|
$
|
1,029
|
|
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities
|
|
|
324
|
|
|
|
776
|
|
|
|
|
|
|
|
|
|
|
OPERATING CASH FLOW(a) |
|
$
|
2,546
|
|
|
$
|
1,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
728
|
|
|
$
|
1,033
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of unrealized gains
|
|
|
124
|
|
|
|
26
|
|
Income tax expense
|
|
|
446
|
|
|
|
661
|
|
Depreciation and amortization of other assets
|
|
|
154
|
|
|
|
166
|
|
Natural gas, oil and NGL depreciation, depletion
and amortization
|
|
|
1,293
|
|
|
|
1,094
|
|
|
|
|
|
|
|
|
|
|
EBITDA(b) |
|
$
|
2,745
|
|
|
$
|
2,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
2,222
|
|
|
$
|
1,029
|
|
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities
|
|
|
324
|
|
|
|
776
|
|
Interest expense, net of unrealized gains on derivatives
|
|
|
67
|
|
|
|
28
|
|
Unrealized gains on natural gas, oil and NGL derivatives
|
|
|
429
|
|
|
|
540
|
|
Net gains on sales of fixed assets
|
|
|
158
|
|
|
|
2
|
|
Impairments of fixed assets and other
|
|
|
(258
|
)
|
|
|
(243
|
)
|
Employee retirement and other termination benefits
|
|
|
(104
|
)
|
|
|
—
|
|
Gains (losses) on sales of investments
|
|
|
(10
|
)
|
|
|
1,030
|
|
Losses on investments
|
|
|
(7
|
)
|
|
|
(120
|
)
|
Impairment of investment
|
|
|
(10
|
)
|
|
|
—
|
|
Stock-based compensation
|
|
|
(56
|
)
|
|
|
(63
|
)
|
Losses on purchases of debt
|
|
|
(17
|
)
|
|
|
—
|
|
Other items
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
EBITDA(b) |
|
$
|
2,745
|
|
|
$
|
2,980
|
|
|
|
|
|
|
|
|
|
|
(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 (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.
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
June 30,
|
|
THREE MONTHS ENDED:
|
|
2013
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
1,834
|
|
|
$
|
912
|
|
|
$
|
2,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gains) losses on natural gas, oil and NGL derivatives
|
|
|
(576
|
)
|
|
|
146
|
|
|
|
(810
|
)
|
Impairment of investment
|
|
|
—
|
|
|
|
10
|
|
|
|
—
|
|
Net gains on sales of fixed assets
|
|
|
(109
|
)
|
|
|
(49
|
)
|
|
|
—
|
|
Impairments of fixed assets and other
|
|
|
231
|
|
|
|
27
|
|
|
|
243
|
|
Net income attributable to noncontrolling interests
|
|
|
(45
|
)
|
|
|
(44
|
)
|
|
|
(65
|
)
|
(Gains) losses on sales of investments
|
|
|
10
|
|
|
|
—
|
|
|
|
(957
|
)
|
Losses on purchases of debt
|
|
|
70
|
|
|
|
—
|
|
|
|
—
|
|
Employee retirement and other termination benefits
|
|
|
7
|
|
|
|
133
|
|
|
|
1
|
|
Other
|
|
|
2
|
|
|
|
(1
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(a) |
|
$
|
1,424
|
|
|
$
|
1,134
|
|
|
$
|
803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
SIX MONTHS ENDED:
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
2,745
|
|
|
$
|
2,980
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized (gains) losses on natural gas, oil and NGL derivatives
|
|
|
(429
|
)
|
|
|
(540
|
)
|
Impairment of investment
|
|
|
10
|
|
|
|
—
|
|
Net gains on sales of fixed assets
|
|
|
(158
|
)
|
|
|
(2
|
)
|
Impairments of fixed assets and other
|
|
|
258
|
|
|
|
243
|
|
Net income attributable to noncontrolling interests
|
|
|
(89
|
)
|
|
|
(89
|
)
|
(Gains) losses on sales of investments
|
|
|
10
|
|
|
|
(957
|
)
|
Losses on purchases of debt
|
|
|
70
|
|
|
|
—
|
|
Employee retirement and other termination benefits
|
|
|
140
|
|
|
|
1
|
|
Other
|
|
|
1
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(a) |
|
$
|
2,558
|
|
|
$
|
1,641
|
|
|
|
|
|
|
|
|
|
|
(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”
MANAGEMENT’S OUTLOOK AS OF AUGUST 1, 2013
Chesapeake periodically provides management guidance on certain factors
that affect its future financial performance. The primary changes from
the company’s May 1, 2013 Outlook are in italicized bold below.
The production guidance provided below assumes that Chesapeake closes
asset sales of approximately $4 billion during 2013. Estimated
production decreases of approximately 37 bcfe in 2013 are associated
with these assets sales and are reflected in the production guidance set
forth below. To the extent the company completes asset sales in excess
of $4 billion during 2013, production guidance may need to be reduced to
reflect such incremental sales.
|
|
|
|
|
|
Chesapeake Energy Corporation Consolidated Projections
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending
12/31/13
|
Estimated Production:
|
|
|
|
|
|
Natural gas – bcf
|
|
|
|
|
1,080 – 1,100
|
Oil – mbbls
|
|
|
|
|
38,000 – 40,000
|
NGL – mbbls(a) |
|
|
|
|
21,000 – 23,000
|
Natural gas equivalent – bcfe
|
|
|
|
|
1,434 – 1,478
|
|
|
|
|
|
|
Daily natural gas equivalent midpoint – mmcfe
|
|
|
|
|
3,990
|
|
|
|
|
|
|
YOY estimated production increase (adjusted for planned asset sales)
|
|
|
|
|
3%
|
|
|
|
|
|
|
NYMEX Price(b) (for calculation of realized hedging
effects only):
|
|
|
|
|
|
Natural gas - $/mcf
|
|
|
|
|
$3.73
|
Oil - $/bbl
|
|
|
|
|
$97.15
|
|
|
|
|
|
|
Estimated Realized Hedging Effects (based on assumed NYMEX prices
above): above):
|
|
|
|
Natural gas - $/mcf
|
|
|
|
|
($0.05)
|
Oil - $/bbl
|
|
|
|
|
($1.70)
|
|
|
|
|
|
|
Estimated Gathering/Marketing/Transportation Differentials to NYMEX
Prices:
|
|
|
|
Natural gas - $/mcf
|
|
|
|
|
$1.25 – 1.40
|
Oil - $/bbl
|
|
|
|
|
$1.00 – 3.00
|
NGL - $/bbl
|
|
|
|
|
$69.00 – 73.00
|
|
|
|
|
|
|
Operating Costs per Mcfe of Projected Production:
|
|
|
|
|
|
Production expense
|
|
|
|
|
$0.85 – 0.90
|
Production taxes
|
|
|
|
|
$0.15 – 0.20
|
General and administrative(c) |
|
|
|
|
$0.25 – 0.30
|
Stock-based compensation (noncash)
|
|
|
|
|
$0.04 – 0.06
|
DD&A of natural gas and liquids assets
|
|
|
|
|
$1.65 – 1.85
|
Depreciation of other assets
|
|
|
|
|
$0.20 – 0.25
|
Interest expense(d) |
|
|
|
|
$0.10 – 0.15
|
|
|
|
|
|
|
Other ($ millions):
|
|
|
|
Marketing, gathering and compression net margin(e) |
|
|
|
|
$100 – 125
|
Oilfield services net margin(e) |
|
|
|
|
$125 – 175
|
Net income attributable to noncontrolling interests and other(f) |
|
|
|
|
($160 – 200)
|
|
|
|
|
|
|
Book Tax Rate
|
|
|
|
|
38%
|
|
|
|
|
|
|
Weighted average shares outstanding (in millions):
|
|
|
|
|
|
Basic
|
|
|
|
|
650 – 655
|
Diluted
|
|
|
|
|
760 – 765
|
|
|
|
|
|
|
Operating cash flow before changes in assets and liabilities(g)(h) |
|
|
|
|
$5,050 – 5,100
|
Drilling and completion costs on proved and unproved properties
|
|
|
|
|
($5,700 – 6,000)
|
Acquisition of unproved properties, net
|
|
|
|
|
($300 – 350)
|
|
|
|
|
|
|
a) Reflects actual and assumed ethane rejection in the 2013 second
quarter and 2013 third quarter, respectively.
|
b) NYMEX natural gas and oil prices have been updated for actual
contract prices through July and June, respectively.
|
c) Excludes expenses associated with noncash stock-based
compensation.
|
d) Does not include unrealized gains or losses on interest rate
derivatives.
|
e) Includes revenue and operating costs and excludes depreciation
and amortization of other assets.
|
f) Net income attributable to noncontrolling interests of Chesapeake
Granite Wash Trust, CHK Utica, L.L.C. and CHK Cleveland Tonkawa,
L.L.C.
|
g) 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.
|
h) Assumes NYMEX prices on open contracts of $3.75 to $4.00 per mcf
and $100.00 per bbl in 2013.
|
|
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative transactions
in order to mitigate a portion of its exposure to adverse changes in
market prices. Please see the quarterly reports on Form 10-Q and annual
reports on Form 10-K filed by Chesapeake with the SEC for detailed
information about derivative instruments the company uses, its
quarter-end and year-end derivative positions and the accounting for
natural gas, oil and NGL derivatives.
The company’s natural gas hedging positions as of July 31, 2013 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Open Natural Gas Swaps; Gains (Losses) from Closed
Natural Gas Trades and Call Option Premiums
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Open
Swaps
(bcf)
|
|
|
Avg. NYMEX
Price of
Open Swaps
|
|
|
Forecasted
Natural Gas
Production
(bcf)
|
|
|
Open Swap
Positions as
a % of
Forecasted
Natural Gas
Production
|
|
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($ in millions)
|
|
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
mcf of Forecasted
Natural Gas
Production
|
Q3 2013
|
|
|
197
|
|
|
$
|
3.73
|
|
|
|
|
|
|
|
|
$
|
7
|
|
|
|
Q4 2013
|
|
|
190
|
|
|
|
3.71
|
|
|
|
|
|
|
|
|
|
(3)
|
|
|
|
Total Q3-Q4 2013
|
|
|
387
|
|
|
$
|
3.72
|
|
|
539
|
|
|
72%
|
|
|
$
|
4
|
|
|
$
|
0.01
|
Total 2014
|
|
|
133
|
|
|
$
|
4.39
|
|
|
|
|
|
|
|
|
$
|
(74)
|
|
|
|
Total 2015
|
|
|
0
|
|
|
|
-
|
|
|
|
|
|
|
|
|
$
|
(131)
|
|
|
|
Total 2016 – 2022
|
|
|
0
|
|
|
|
-
|
|
|
|
|
|
|
|
|
$
|
(187)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Natural Gas Three-Way Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Open
Collars
(bcf)
|
|
|
Avg. NYMEX
Sold Put Price
|
|
|
Avg. NYMEX
Bought Put Price
|
|
|
Avg. NYMEX
Ceiling Price
|
|
|
Forecasted
Natural Gas
Production
(bcf)
|
|
|
Open Collars as a % of
Forecasted
Natural Gas
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2013
|
|
|
18
|
|
|
|
$
|
3.03
|
|
|
|
$
|
3.55
|
|
|
|
$
|
4.03
|
|
|
|
|
|
|
|
|
|
Q4 2013
|
|
|
18
|
|
|
|
|
3.03
|
|
|
|
|
3.55
|
|
|
|
|
4.03
|
|
|
|
|
|
|
|
|
|
Total Q3-Q4 2013
|
|
|
36
|
|
|
|
$
|
3.03
|
|
|
|
$
|
3.55
|
|
|
|
$
|
4.03
|
|
|
|
539
|
|
|
|
7
|
%
|
Total 2014
|
|
|
18
|
|
|
|
$
|
3.50
|
|
|
|
$
|
4.00
|
|
|
|
$
|
4.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaptions
|
|
|
|
|
|
|
|
|
|
|
|
Swaptions
(bcf)
|
|
Avg. NYMEX
Strike Price
|
|
Forecasted
Natural Gas
Production
(bcf)
|
|
Swaptions
as a % of
Forecasted Natural
Gas
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Q3-Q4 2013
|
|
0
|
|
|
$
|
-
|
|
|
539
|
|
|
0
|
%
|
Total 2014
|
|
12
|
|
|
$
|
4.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Written Call Options
|
|
|
|
|
|
|
|
|
|
|
|
Call Options
(bcf)
|
|
Avg. NYMEX
Strike Price
|
|
Forecasted
Natural Gas
Production
(bcf)
|
|
Call Options
as a % of
Forecasted Natural
Gas
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Q3-Q4 2013
|
|
0
|
|
|
$
|
-
|
|
|
539
|
|
|
0
|
%
|
Total 2016 – 2020
|
|
193
|
|
|
$
|
9.92
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Protection Swaps
|
|
|
|
|
|
|
|
|
Volume (bcf)
|
|
Avg. NYMEX less
|
|
|
|
|
|
|
|
Q3 2013
|
|
11
|
|
|
$
|
0.21
|
Q4 2013
|
|
11
|
|
|
|
0.21
|
Total Q3-Q4 2013
|
|
22
|
|
|
$
|
0.21
|
Total 2014
|
|
28
|
|
|
$
|
0.32
|
Total 2015
|
|
31
|
|
|
$
|
0.34
|
Total 2016 - 2022
|
|
8
|
|
|
$
|
1.02
|
|
|
|
|
|
|
|
The company’s crude oil hedging positions as of July 31, 2013 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
|
|
Forecasted
Oil
Production
(mbbls)
|
|
Open Swap
Positions as
a % of
Forecasted
Oil
Production
|
|
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($ in millions)
|
|
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Oil
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2013
|
|
8,834
|
|
|
$
|
95.68
|
|
|
|
|
|
|
|
|
$
|
2
|
|
|
|
|
Q4 2013
|
|
9,181
|
|
|
|
95.59
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
Total Q3-Q4 2013
|
|
18,015
|
|
|
$
|
95.64
|
|
|
19,178
|
|
|
94
|
%
|
|
$
|
4
|
|
|
$
|
$0.18
|
Total 2014
|
|
21,358
|
|
|
$
|
93.76
|
|
|
|
|
|
|
|
|
$
|
(151
|
)
|
|
|
|
Total 2015
|
|
693
|
|
|
$
|
89.48
|
|
|
|
|
|
|
|
|
$
|
265
|
|
|
|
|
Total 2016 – 2022
|
|
0
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
$
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swaptions
|
|
|
|
|
|
|
|
|
|
|
|
Swaptions
(mbbls)
|
|
Avg. NYMEX
Strike Price
|
|
Forecasted
Natural Gas
Production
(mbbls)
|
|
Swaptions
as a % of
Forecasted Natural
Gas
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Q3-Q4 2013
|
|
0
|
|
|
$
|
-
|
|
|
19,178
|
|
|
0
|
%
|
Total 2014
|
|
2,920
|
|
|
$
|
106.69
|
|
|
|
|
|
|
|
Total 2015
|
|
2,368
|
|
|
$
|
106.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Written Call Options
|
|
|
|
|
|
|
|
|
|
|
|
Call Options
(mbbls)
|
|
Avg. NYMEX
Strike Price
|
|
Forecasted
Oil
Production
(mbbls)
|
|
Call Options
as a % of
Forecasted Oil
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q3 2013
|
|
1,975
|
|
|
$
|
97.90
|
|
|
|
|
|
|
|
Q4 2013
|
|
1,975
|
|
|
|
97.90
|
|
|
|
|
|
|
|
Total Q3-Q4 2013
|
|
3,950
|
|
|
$
|
97.90
|
|
|
19,178
|
|
|
21
|
%
|
Total 2014
|
|
14,692
|
|
|
$
|
97.22
|
|
|
|
|
|
|
|
Total 2015
|
|
24,680
|
|
|
$
|
100.45
|
|
|
|
|
|
|
|
Total 2016 – 2017
|
|
24,220
|
|
|
$
|
100.07
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Basis Protection Swaps
|
|
|
|
|
|
|
|
Volume (mbbls)
|
|
Avg. NYMEX plus
|
|
|
|
|
|
|
|
Q3 2013
|
|
736
|
|
|
$
|
10.07
|
Q4 2013
|
|
0
|
|
|
|
-
|
Total Q3-Q4 2013
|
|
736
|
|
|
$
|
10.07
|
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Copyright Business Wire 2013