Chesapeake Energy Corporation (NYSE:CHK) today reported financial and
operational results for the 2014 first quarter. Key information related
to the first quarter and the company's full-year 2014 Outlook is as
follows:
-
2014 first quarter adjusted net income per fully diluted share
increases 97% to $0.59 from $0.30 in the 2013 first quarter
-
Adjusted ebitda increases 34% year over year to $1.5 billion
-
Average production of 675,200 boe per day increases 11% year
over year, adjusted for 2013 asset sales
-
Total capital expenditures of $850 million decrease
approximately 50% year over year
-
2014 full-year adjusted production growth outlook increased to 9
– 12% from 8 – 10%
-
2014 full-year operating cash flow outlook raised to $5.8 – $6.0
billion from $5.1 – $5.3 billion
Doug Lawler, Chesapeake’s Chief Executive Officer, commented, "This was
an important and defining quarter for Chesapeake, as our competitive
capital allocation, cost leadership and capital efficiency initiatives
are driving tangible improvements in the company's growth profile and
financial performance. We are raising our 2014 total production growth
outlook on an adjusted basis to 9 – 12% to reflect higher-than-expected
natural gas liquids volumes. Additionally, we are raising the midpoint
of our 2014 operating cash flow outlook by $700 million, or 13%, due
primarily to our increased production outlook, better-than-expected
first quarter cash flow and an increase in our benchmark commodity price
assumptions for the full year."
For the 2014 first quarter, Chesapeake reported net income available to
common stockholders of $374 million, or $0.54 per fully diluted share.
Items typically excluded by securities analysts in their earnings
estimates reduced net income available to common stockholders for the
2014 first quarter by approximately $31 million on an after-tax basis.
Adjusting for these items, 2014 first quarter net income available to
common stockholders was $405 million, or $0.59 per fully diluted share,
which compares to adjusted net income available to common stockholders
of $183 million, or $0.30 per fully diluted share, in the 2013 first
quarter. This increase is primarily the result of substantially higher
year-over-year realized natural gas prices, higher oil and natural gas
liquids (NGL) production and lower per unit production and general and
administrative (G&A) expenses, partially offset by higher interest
expense during the quarter.
Adjusted ebitda was $1.515 billion in the 2014 first quarter, an
increase of 34% year over year. Operating cash flow, which is cash flow
provided by operating activities before changes in assets and
liabilities, was $1.614 billion in the 2014 first quarter, an increase
of 37% year over year.
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 12 – 14 of this release.
2014 First Quarter Average Daily Production of 675 Mboe Increases 11%
Year over Year, Adjusted for 2013 Asset Sales
Chesapeake’s daily production for the 2014 first quarter averaged
675,200 barrels of oil equivalent (boe), a year-over-year increase of
11%, adjusted for asset sales. Average daily production consisted of
approximately 109,500 barrels (bbls) of oil, 84,200 bbls of NGL and 2.9
billion cubic feet (bcf) of natural gas. Chesapeake estimates that
weather-related downtime adversely impacted its production during the
2014 first quarter by approximately 7,600 boe per day, predominantly in
the Mid-Continent region. This production loss was within the range of
Chesapeake's budgeted winter weather downtime, which was previously
accounted for in the company's 2014 Outlook issued on February 6, 2014.
On an adjusted basis, 2014 first quarter average daily oil production
increased 20% year over year, average daily NGL production increased 63%
year over year and natural gas production increased 4% year over year.
Chesapeake Realizes Substantially Higher Natural Gas Prices during
the 2014 First Quarter
Chesapeake's realized natural gas price increased to $3.27 per thousand
cubic feet (mcf) during the 2014 first quarter from $1.90 per mcf in the
2013 fourth quarter, or approximately 72%. The increase was due to
higher natural gas prices in general resulting from cold winter
temperatures as well as Chesapeake's increased access to premium priced
markets in the Northeast. More specifically, the company had firm
natural gas transportation capacity commitments in place that enabled it
to access the New York City market where natural gas prices during the
2014 first quarter traded at a substantial premium to NYMEX Henry Hub
benchmark prices. As a result, Chesapeake's natural gas price
differential on a companywide basis decreased to $1.08 per mcf in the
2014 first quarter from $1.76 per mcf in the 2013 fourth quarter.
Asset Sales Update
Chesapeake continues to pursue opportunities to high-grade its portfolio
to focus on assets that best fit 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.
During the 2014 first quarter the company received total proceeds of
approximately $520 million from asset sales, including $209 million of
net proceeds from the sale of its common equity ownership interest in
Chaparral Energy, Inc.; $159 million from the sale of compression units
to Access Midstream Partners, L.P. (NYSE:ACMP); and $152 million of net
proceeds from the sale of real estate and other noncore assets.
Additionally, Chesapeake received $362 million in April upon the closing
of the previously announced sale of compression assets to Exterran
Partners, L.P. (NASDAQ:EXLP). Along with proceeds from other
miscellaneous asset sales, this brings year-to-date asset sale proceeds
to more than $925 million. Chesapeake will provide an update on
additional projected asset sales for the remainder of the year in
conjunction with its Analyst Day on May 16.
On February 24, 2014, Chesapeake announced that it is pursuing strategic
alternatives for its oilfield services division, Chesapeake Oilfield
Services (COS), including a potential spin-off to Chesapeake
shareholders or an outright sale. The company continues to evaluate both
alternatives and will provide an update upon final determination of the
path forward. Potential proceeds or dividend to Chesapeake upon the sale
or spin-off of COS would be incremental to the anticipated asset sales
detailed above.
Capital Spending and Cost Overview
Chesapeake's total capital expenditures in the 2014 first quarter were
approximately $850 million, of which drilling and completion capital
expenditures were approximately $729 million. The company invested cash
of $882 million during the 2014 first quarter in drilling and completion
activities, which was partially offset by lower-than-estimated drilling
and completion costs and other adjustments, related to prior periods, of
approximately $153 million. This level of expenditures represents a
decrease of approximately $422 million, or 37%, compared to the 2013
fourth quarter. The sequential decrease is primarily the result of
improving capital efficiencies and approximately 15% fewer well
completions.
Net expenditures for the acquisition of unproved properties were
approximately $24 million and other capital expenditures were
approximately $97 million. In addition, the company purchased rigs and
compressors previously sold under long-term lease arrangements for
approximately $340 million as part of a strategic initiative to reduce
complexity and future commitments as well as to facilitate asset sales
and a possible spin-off or sale of COS.
Chesapeake spud a total of 299 gross wells and completed 234 gross wells
during the 2014 first quarter, compared to 239 gross wells spud and 274
gross wells completed during the 2013 fourth quarter. Given expected
increases in completion activity during the remainder of 2014, the
company is reiterating its full-year capital expenditure guidance of
$5.2 - $5.6 billion. Chesapeake plans to run a more balanced pace of
drilling and completion operations in 2014 than it did 2013, when it
substantially reduced its inventory of nonproducing wells.
Chesapeake's focus on cost leadership continues to generate reductions
in production and G&A expenses. Average production expenses during the
2014 first quarter were $4.73 per boe, a decrease of 8% from the 2013
first quarter. G&A expenses (excluding share-based compensation and
restructuring and other termination costs) during the 2014 first quarter
were $1.09 per boe, a decrease of 27% from the 2013 first quarter.
Interest expense (excluding unrealized gains or losses on interest rate
derivatives) during the 2014 first quarter was $0.90 per boe, compared
to $0.25 per boe in the 2013 first quarter, as the company capitalized a
smaller percentage of its interest cost due to a decrease in the balance
of its unevaluated natural gas and oil properties.
A complete summary of the company’s guidance for 2014 is provided in the
Outlook dated May 7, 2014, attached to this release as Schedule "A”
beginning on Page 15.
Operational Update – Key Assets
The company continues to achieve strong operational results and
well-cost reductions in each of its most active plays.
Eagle Ford Shale (South Texas):
Eagle Ford net production averaged approximately 88,000 boe per day
(187,000 gross operated boe per day) during the 2014 first quarter.
Adjusted for 2013 asset sales, this represents an increase of 26% year
over year and 1% sequentially. First quarter production was adversely
impacted by temporary downtime at gas gathering and processing
facilities, operated and competitor offset activity-related shut-ins and
weather-related activity reductions. These issues have moderated during
April and May, and the company is projecting a higher sequential
quarterly growth trajectory for Eagle Ford production during the
remainder of the year. Approximately 64% of the company’s Eagle Ford
production in the 2014 first quarter was oil, 15% was NGL and 21% was
natural gas.
Chesapeake operated an average of 18 rigs and connected 81 gross wells
to sales during the 2014 first quarter in the Eagle Ford, compared to 12
average operated rigs and 65 gross wells connected to sales during the
2013 fourth quarter. The average peak production rate of the 81 wells
that commenced first production in the Eagle Ford during the 2014 first
quarter was approximately 885 boe per day.
As of March 31, 2014, Chesapeake had 945 producing wells and 114 wells
awaiting pipeline connection or in various stages of completion in the
Eagle Ford.
Mid-Continent (Oklahoma, Texas Panhandle,
southern Kansas): Chesapeake's production in the
Mid-Continent comes primarily from five plays: the Mississippi Lime,
Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net
production from these plays during the 2014 first quarter averaged
101,000 boe per day (177,000 gross operated boe per day). Adjusted for
2013 asset sales, Mid-Continent production increased 4% year over year
and decreased 3% sequentially. The sequential production decrease
compared to the 2013 fourth quarter was primarily driven by the impact
of severe winter weather during the 2014 first quarter as well as fewer
new well connections. Approximately 32% of the company’s Mid-Continent
production during the 2014 first quarter was oil, 24% was NGL and 44%
was natural gas.
During the 2014 first quarter Chesapeake operated an average of 17 rigs
and connected 52 gross wells to sales, compared to 17 average operated
rigs and 70 gross wells connected to sales during the 2013 fourth
quarter. The average peak production rate of the 52 wells that commenced
first production in the Mid-Continent during the 2014 first quarter was
approximately 925 boe per day.
As of March 31, 2014, the company had 42 wells awaiting pipeline
connection or in various stages of completion in the Mid-Continent.
Utica Shale (Ohio, Pennsylvania, West Virginia):
Utica net production averaged approximately 50,000 boe per day (90,000
gross operated boe per day) during the 2014 first quarter, an increase
of 422% year over year and 59% sequentially from the 2013 fourth
quarter. Approximately 10% of the company’s Utica production during the
2014 first quarter was oil, 30% was NGL and 60% was natural gas.
During the 2014 first quarter Chesapeake operated an average of nine
rigs and connected 47 gross wells to sales in the Utica, compared to
nine average operated rigs and 49 gross wells connected to sales during
the 2013 fourth quarter. The average peak production rate of the 47
wells that commenced first production in the Utica during the 2014 first
quarter was approximately 1,180 boe per day.
As of March 31, 2014, Chesapeake had drilled a total of 485 wells in the
Utica, which included 274 producing wells and 211 wells awaiting
pipeline connection or in various stages of completion.
Haynesville Shale (Northwest Louisiana, East
Texas): Chesapeake’s 2014 first quarter average net
production in the Haynesville was approximately 495 million cubic feet
of natural gas equivalent (mmcfe) per day (780 gross operated mmcfe per
day). Adjusted for 2013 asset sales, this represents a decrease of 41%
year over year and 8% sequentially. Based on the company's current
drilling program, net Haynesville production is expected to return to
sequential growth in the 2014 third quarter. All of the company's
production in the Haynesville consists of natural gas.
During the 2014 first quarter Chesapeake operated an average of seven
rigs and connected seven gross wells to sales, compared to four average
operated rigs and 12 gross wells connected to sales during the 2013
fourth quarter. The company has achieved substantial drilling and
completion cost reductions in the Haynesville. Most notably, two wells
were drilled and completed during the 2014 first quarter for
approximately $7 million each. The average peak production rate of the
seven wells that commenced first production in the Haynesville during
the 2014 first quarter was approximately 13.1 mmcfe per day.
As of March 31, 2014, Chesapeake had 14 wells awaiting pipeline
connection or in various stages of completion in the Haynesville.
Northern Marcellus Shale (Pennsylvania):
Chesapeake's production from the northern Marcellus continued to
grow during the 2014 first quarter. Average net production in this play
was approximately 910 mmcfe per day (2,180 gross operated mmcfe per
day), an increase of 28% year over year and 3% sequentially. All of the
company's production in the northern Marcellus consists of natural gas.
During the 2014 first quarter Chesapeake operated an average of five
rigs and connected 22 gross wells to sales, compared to five average
operated rigs and 33 gross wells connected to sales during the 2013
fourth quarter. The average peak production rate of the 22 wells that
commenced first production in the northern Marcellus during the 2014
first quarter was approximately 10.9 mmcfe per day.
As of March 31, 2014, Chesapeake had 110 wells awaiting pipeline
connection or in various stages of completion in the northern Marcellus.
Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational
results during the 2014 first quarter and compares them to results in
prior periods.
|
|
Three Months Ended
|
|
|
03/31/14
|
|
12/31/13
|
|
03/31/13
|
Oil equivalent production (in mmboe)
|
|
60.8
|
|
|
61.2
|
|
|
59.7
|
|
Oil production (in mmbbls)
|
|
9.9
|
|
|
10.2
|
|
|
9.3
|
|
Average realized oil price ($/bbl)(a)
|
|
85.08
|
|
|
89.58
|
|
|
94.85
|
|
Oil as % of total production
|
|
16
|
|
|
17
|
|
|
16
|
|
NGL production (in mmbbls)
|
|
7.6
|
|
|
5.9
|
|
|
4.9
|
|
Average realized NGL price ($/bbl)(a)
|
|
29.23
|
|
|
31.76
|
|
|
28.25
|
|
NGL as % of total production
|
|
13
|
|
|
9
|
|
|
8
|
|
Natural gas production (in bcf)
|
|
260
|
|
|
271
|
|
|
273
|
|
Average realized natural gas price ($/mcf)(a)
|
|
3.27
|
|
|
1.90
|
|
|
2.13
|
|
Natural gas as % of total production
|
|
71
|
|
|
74
|
|
|
76
|
|
Production expenses ($/boe)
|
|
(4.73
|
)
|
|
(4.62
|
)
|
|
(5.14
|
)
|
Production taxes ($/boe)
|
|
(0.83
|
)
|
|
(0.91
|
)
|
|
(0.89
|
)
|
General and administrative costs ($/boe)(c)
|
|
(1.09
|
)
|
|
(1.79
|
)
|
|
(1.50
|
)
|
Share-based compensation ($/boe)
|
|
(0.21
|
)
|
|
(0.19
|
)
|
|
(0.34
|
)
|
DD&A of natural gas and liquids properties ($/boe)
|
|
(10.33
|
)
|
|
(10.53
|
)
|
|
(10.86
|
)
|
D&A of other assets ($/boe)
|
|
(1.29
|
)
|
|
(1.32
|
)
|
|
(1.31
|
)
|
Interest expense ($/boe)(a)
|
|
(0.90
|
)
|
|
(0.86
|
)
|
|
(0.25
|
)
|
Capitalized interest ($ in millions)
|
|
178
|
|
|
182
|
|
|
228
|
|
Marketing, gathering and compression net margin
($ in millions)(d)
|
|
35
|
|
|
9
|
|
|
36
|
|
Oilfield services net margin ($ in millions)(d)
|
|
45
|
|
|
52
|
|
|
35
|
|
Operating cash flow ($ in millions)(e)
|
|
1,614
|
|
|
995
|
|
|
1,179
|
|
Operating cash flow ($/boe)
|
|
26.55
|
|
|
16.27
|
|
|
19.75
|
|
Adjusted ebitda ($ in millions)(f)
|
|
1,515
|
|
|
1,132
|
|
|
1,134
|
|
Adjusted ebitda ($/boe)
|
|
24.94
|
|
|
18.51
|
|
|
19.00
|
|
Net income (loss) available to common stockholders
($ in millions)
|
|
374
|
|
|
(159
|
)
|
|
15
|
|
Earnings (loss) per share – diluted ($)
|
|
0.54
|
|
|
(0.24
|
)
|
|
0.02
|
|
Adjusted net income available to common
stockholders ($ in millions)(g)
|
|
405
|
|
|
161
|
|
|
183
|
|
Adjusted earnings per share – diluted ($)
|
|
0.59
|
|
|
0.27
|
|
|
0.30
|
|
(a) Includes the effects of realized gains (losses) from hedging, but
excludes the effects of unrealized gains (losses) from hedging.
(b)
"Liquids” includes both oil and NGL.
(c) Excludes expenses
associated with share-based compensation and restructuring and other
termination costs.
(d) Includes revenue and operating expenses and
excludes depreciation and amortization of other assets.
(e) Defined
as cash flow provided by operating activities before changes in assets
and liabilities.
(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 14.
(g)
Defined as net income available to common stockholders, as adjusted to
remove the effects of certain items detailed on Page 12.
2014 First Quarter Financial and Operational Results Conference Call
Information
A conference call to discuss this release has been scheduled for
Wednesday, May 7, 2014, at 9:00 am EDT. The telephone number to access
the conference call is 913-312-0823 or toll-free 877-627-6580.
The passcode for the call is 5839213. 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,
May 7, 2014, and will run through 2:00 pm EDT on Wednesday, May 21,
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 5839213.
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, compression and oilfield services
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 that give our current expectations or
forecasts of future events. They include production forecasts,
estimates of operating costs, planned development drilling, expected
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. 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 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. Any separation of COS
is subject to satisfaction of several conditions, some of which are
beyond our control, including market conditions, board approvals,
consents, regulatory review and approvals, among others. There can be no
assurance that the proposed separation will lead to a sale or spin-off
or any other transaction, or that if any transaction is pursued, it will
be consummated. 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 Ended March 31,
|
|
|
2014
|
|
2013
|
REVENUES:
|
|
|
|
|
|
|
|
|
Natural gas, oil and NGL
|
|
$
|
1,766
|
|
|
$
|
1,453
|
|
Marketing, gathering and compression
|
|
|
3,015
|
|
|
|
1,781
|
|
Oilfield services
|
|
|
265
|
|
|
|
190
|
|
Total Revenues
|
|
|
5,046
|
|
|
|
3,424
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES:
|
|
|
|
|
|
|
|
|
Natural gas, oil and NGL production
|
|
|
288
|
|
|
|
307
|
|
Production taxes
|
|
|
50
|
|
|
|
53
|
|
Marketing, gathering and compression
|
|
|
2,980
|
|
|
|
1,745
|
|
Oilfield services
|
|
|
220
|
|
|
|
155
|
|
General and administrative
|
|
|
79
|
|
|
|
110
|
|
Restructuring and other termination costs
|
|
|
(7
|
)
|
|
|
133
|
|
Natural gas, oil and NGL depreciation, depletion and
amortization
|
|
|
628
|
|
|
|
648
|
|
Depreciation and amortization of other assets
|
|
|
78
|
|
|
|
78
|
|
Impairments of fixed assets and other
|
|
|
20
|
|
|
|
27
|
|
Net gains on sales of fixed assets
|
|
|
(23
|
)
|
|
|
(49
|
)
|
Total Operating Expenses
|
|
|
4,313
|
|
|
|
3,207
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM OPERATIONS
|
|
|
733
|
|
|
|
217
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(39
|
)
|
|
|
(21
|
)
|
Losses on investments
|
|
|
(21
|
)
|
|
|
(37
|
)
|
Net gains on sales of investments
|
|
|
67
|
|
|
|
—
|
|
Other income
|
|
|
6
|
|
|
|
6
|
|
Total Other Income (Expense)
|
|
|
13
|
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES
|
|
|
746
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE:
|
|
|
|
|
|
|
|
|
Current income taxes
|
|
|
3
|
|
|
|
1
|
|
Deferred income taxes
|
|
|
277
|
|
|
|
62
|
|
Total Income Tax Expense
|
|
|
280
|
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
|
466
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interests
|
|
|
(41
|
)
|
|
|
(44
|
)
|
|
|
|
|
|
|
|
|
|
NET INCOME ATTRIBUTABLE TO CHESAPEAKE
|
|
|
425
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
(43
|
)
|
|
|
(43
|
)
|
Earnings allocated to participating securities
|
|
|
(8
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
|
|
$
|
374
|
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.57
|
|
|
$
|
0.02
|
|
Diluted
|
|
$
|
0.54
|
|
|
$
|
0.02
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING
(in millions):
|
|
|
|
|
|
|
|
|
Basic
|
|
|
658
|
|
|
|
651
|
|
Diluted
|
|
|
765
|
|
|
|
651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
($ in millions)
|
(unaudited)
|
|
|
|
March 31, 2014
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,004
|
|
|
$
|
837
|
Other current assets
|
|
|
3,271
|
|
|
|
2,819
|
Total Current Assets
|
|
|
4,275
|
|
|
|
3,656
|
|
|
|
|
|
|
|
|
Property and equipment, (net)
|
|
|
37,522
|
|
|
|
37,134
|
Other assets
|
|
|
808
|
|
|
|
992
|
Total Assets
|
|
$
|
42,605
|
|
|
$
|
41,782
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
5,958
|
|
|
$
|
5,515
|
Long-term debt, net of discounts
|
|
|
12,653
|
|
|
|
12,886
|
Other long-term liabilities
|
|
|
1,689
|
|
|
|
1,834
|
Deferred income tax liabilities
|
|
|
3,828
|
|
|
|
3,407
|
Total Liabilities
|
|
|
24,128
|
|
|
|
23,642
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
3,062
|
|
|
|
3,062
|
Noncontrolling interests
|
|
|
2,136
|
|
|
|
2,145
|
Common stock and other stockholders’ equity
|
|
|
13,279
|
|
|
|
12,933
|
Total Equity
|
|
|
18,477
|
|
|
|
18,140
|
|
|
|
|
|
|
|
|
Total Liabilities and Equity
|
|
$
|
42,605
|
|
|
$
|
41,782
|
|
|
|
|
|
|
|
|
Common Shares Outstanding (in millions)
|
|
|
663
|
|
|
|
664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
|
CAPITALIZATION
|
($ in millions)
|
(unaudited)
|
|
|
|
March 31, 2014
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
Total debt, net of unrestricted cash
|
|
$
|
11,965
|
|
|
$
|
12,049
|
|
Preferred stock
|
|
|
3,062
|
|
|
|
3,062
|
|
Noncontrolling interests(a)
|
|
|
2,136
|
|
|
|
2,145
|
|
Common stock and other stockholders’ equity
|
|
|
13,279
|
|
|
|
12,933
|
|
Total
|
|
$
|
30,442
|
|
|
$
|
30,189
|
|
|
|
|
|
|
|
|
|
|
Total debt to capitalization ratio
|
|
|
39
|
%
|
|
|
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
|
|
|
306
|
|
|
|
314
|
|
Other
|
|
|
8
|
|
|
|
9
|
|
Total
|
|
$
|
2,136
|
|
|
$
|
2,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
|
SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES
AND INTEREST EXPENSE
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2014
|
|
2013
|
Net Production:
|
|
|
|
|
|
|
|
|
Natural gas (bcf)
|
|
|
260.0
|
|
|
|
273.1
|
|
Oil (mmbbl)
|
|
|
9.9
|
|
|
|
9.3
|
|
NGL (mmbbl)
|
|
|
7.6
|
|
|
|
4.9
|
|
Oil equivalent (mmboe)
|
|
|
60.8
|
|
|
|
59.7
|
|
|
|
|
|
|
|
|
|
|
Natural Gas, Oil and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
1,005
|
|
|
$
|
573
|
|
Natural gas derivatives – realized gains (losses)(a)
|
|
|
(154
|
)
|
|
|
8
|
|
Natural gas derivatives – unrealized gains (losses)(a)
|
|
|
(154
|
)
|
|
|
(278
|
)
|
Total Natural Gas Sales
|
|
|
697
|
|
|
|
303
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
|
922
|
|
|
|
884
|
|
Oil derivatives – realized gains (losses)(a)
|
|
|
(84
|
)
|
|
|
(4
|
)
|
Oil derivatives – unrealized gains (losses)(a)
|
|
|
10
|
|
|
|
132
|
|
Total Oil Sales
|
|
|
848
|
|
|
|
1,012
|
|
|
|
|
|
|
|
|
|
|
NGL sales
|
|
|
221
|
|
|
|
138
|
|
NGL derivatives – realized gains (losses)(a)
|
|
|
—
|
|
|
|
—
|
|
NGL derivatives – unrealized gains (losses)(a)
|
|
|
—
|
|
|
|
—
|
|
Total NGL Sales
|
|
|
221
|
|
|
|
138
|
|
Total Natural Gas, Oil and NGL Sales
|
|
$
|
1,766
|
|
|
$
|
1,453
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price – excluding gains (losses) on derivatives:
|
|
|
|
|
|
|
|
|
Natural gas ($ per mcf)
|
|
$
|
3.86
|
|
|
$
|
2.10
|
|
Oil ($ per bbl)
|
|
$
|
93.60
|
|
|
$
|
95.23
|
|
NGL ($ per bbl)
|
|
$
|
29.23
|
|
|
$
|
28.25
|
|
Oil equivalent ($ per boe)
|
|
$
|
35.35
|
|
|
$
|
26.71
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price – including realized gains (losses) on
derivatives:
|
|
|
|
|
|
|
|
|
Natural gas ($ per mcf)
|
|
$
|
3.27
|
|
|
$
|
2.13
|
|
Oil ($ per bbl)
|
|
$
|
85.08
|
|
|
$
|
94.85
|
|
NGL ($ per bbl)
|
|
$
|
29.23
|
|
|
$
|
28.25
|
|
Oil equivalent ($ per boe)
|
|
$
|
31.44
|
|
|
$
|
26.79
|
|
|
|
|
|
|
|
|
|
|
Interest Expense (Income) ($ in millions):
|
|
|
|
|
|
|
|
|
Interest(b)
|
|
$
|
58
|
|
|
$
|
17
|
|
Derivatives – realized (gains) losses(c)
|
|
|
(3
|
)
|
|
|
(2
|
)
|
Derivatives – unrealized (gains) losses(c)
|
|
|
(16
|
)
|
|
|
6
|
|
Total Interest Expense
|
|
$
|
39
|
|
|
$
|
21
|
|
(a) Realized gains and losses include the following items: (i)
settlements of non-designated 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:
|
|
March 31, 2014
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
Beginning cash
|
|
$
|
837
|
|
|
$
|
287
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
1,291
|
|
|
|
924
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Drilling and completion costs on proved and unproved properties(a)
|
|
|
(894
|
)
|
|
|
(1,566
|
)
|
Acquisition of proved and unproved properties(b)
|
|
|
(179
|
)
|
|
|
(255
|
)
|
Sale of proved and unproved properties
|
|
|
42
|
|
|
|
165
|
|
Geological and geophysical costs
|
|
|
(4
|
)
|
|
|
(13
|
)
|
Cash paid to purchase leased rigs and compressors
|
|
|
(340
|
)
|
|
|
—
|
|
Additions to other property and equipment
|
|
|
(97
|
)
|
|
|
(330
|
)
|
Proceeds from sales of other assets
|
|
|
239
|
|
|
|
201
|
|
Additions to investments
|
|
|
(3
|
)
|
|
|
(3
|
)
|
Proceeds from sales of investments
|
|
|
239
|
|
|
|
—
|
|
Other
|
|
|
(2
|
)
|
|
|
56
|
|
Total cash used in investing activities
|
|
|
(999
|
)
|
|
|
(1,745
|
)
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
(125
|
)
|
|
|
567
|
|
Change in cash and cash equivalents
|
|
|
167
|
|
|
|
(254
|
)
|
Ending cash
|
|
$
|
1,004
|
|
|
$
|
33
|
|
(a) Includes capitalized interest of $12 million and $16 million for the
three months ended March 31, 2014 and 2013, respectively.
(b) Includes capitalized interest of $158 million and $207 million for
the three months ended March 31, 2014 and 2013, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY CORPORATION
|
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS
|
($ in millions, except per share data)
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED:
|
|
March 31, 2014
|
|
December 31, 2013
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$
|
374
|
|
|
$
|
(159
|
)
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses on derivatives
|
|
|
80
|
|
|
|
13
|
|
|
|
94
|
|
Restructuring and other termination costs
|
|
|
(4
|
)
|
|
|
28
|
|
|
|
83
|
|
Impairments of fixed assets and other
|
|
|
12
|
|
|
|
126
|
|
|
|
16
|
|
Net gains on sales of fixed assets
|
|
|
(14
|
)
|
|
|
(7
|
)
|
|
|
(30
|
)
|
Losses on investments
|
|
|
—
|
|
|
|
84
|
|
|
|
6
|
|
Net gains on sales of investments
|
|
|
(42
|
)
|
|
|
—
|
|
|
|
—
|
|
Losses on purchases of debt and extinguishment of other financing
|
|
|
—
|
|
|
|
76
|
|
|
|
—
|
|
Other
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income available to common stockholders(a)
|
|
|
405
|
|
|
|
161
|
|
|
|
183
|
|
Preferred stock dividends
|
|
|
43
|
|
|
|
43
|
|
|
|
43
|
|
Earnings allocated to participating securities
|
|
|
8
|
|
|
|
—
|
|
|
|
—
|
|
Total adjusted net income attributable to Chesapeake
|
|
$
|
456
|
|
|
$
|
204
|
|
|
$
|
226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fully diluted shares outstanding (in millions)(b)
|
|
|
767
|
|
|
|
767
|
|
|
|
761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted earnings per share assuming dilution(a)
|
|
$
|
0.59
|
|
|
$
|
0.27
|
|
|
$
|
0.30
|
|
(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:
|
|
March 31, 2014
|
|
December 31, 2013
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
1,291
|
|
|
$
|
1,028
|
|
|
$
|
924
|
|
Changes in assets and liabilities
|
|
|
323
|
|
|
|
(33
|
)
|
|
|
255
|
|
OPERATING CASH FLOW(a)
|
|
$
|
1,614
|
|
|
$
|
995
|
|
|
$
|
1,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED:
|
|
March 31, 2014
|
|
December 31, 2013
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
466
|
|
|
$
|
(74
|
)
|
|
$
|
102
|
|
Interest expense
|
|
|
39
|
|
|
|
63
|
|
|
|
21
|
|
Income tax expense (benefit)
|
|
|
280
|
|
|
|
(45
|
)
|
|
|
63
|
|
Depreciation and amortization of other assets
|
|
|
78
|
|
|
|
80
|
|
|
|
78
|
|
Natural gas, oil and NGL depreciation, depletion and amortization
|
|
|
628
|
|
|
|
644
|
|
|
|
648
|
|
EBITDA(b)
|
|
$
|
1,491
|
|
|
$
|
668
|
|
|
$
|
912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED:
|
|
March 31, 2014
|
|
December 31, 2013
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
$
|
1,291
|
|
|
$
|
1,028
|
|
|
$
|
924
|
|
Changes in assets and liabilities
|
|
|
323
|
|
|
|
(33
|
)
|
|
|
255
|
|
Interest expense, net of unrealized gains (losses) on derivatives
|
|
|
55
|
|
|
|
53
|
|
|
|
15
|
|
Natural gas, oil and NGL derivative gains (losses), net
|
|
|
(382
|
)
|
|
|
(13
|
)
|
|
|
(142
|
)
|
Cash (receipts) payments on natural gas, oil and NGL derivative
settlements, net
|
|
|
168
|
|
|
|
30
|
|
|
|
(19
|
)
|
Share-based compensation
|
|
|
(20
|
)
|
|
|
(20
|
)
|
|
|
(32
|
)
|
Restructuring and other termination costs
|
|
|
9
|
|
|
|
(11
|
)
|
|
|
(105
|
)
|
Impairments of fixed assets and other
|
|
|
(12
|
)
|
|
|
(166
|
)
|
|
|
(27
|
)
|
Net gains on sales of fixed assets
|
|
|
23
|
|
|
|
12
|
|
|
|
49
|
|
Losses on investments
|
|
|
(21
|
)
|
|
|
(189
|
)
|
|
|
(39
|
)
|
Net gains on sales of investments
|
|
|
67
|
|
|
|
—
|
|
|
|
—
|
|
Losses on purchases of debt and extinguishment of other financing
|
|
|
—
|
|
|
|
(3
|
)
|
|
|
—
|
|
Other items
|
|
|
(10
|
)
|
|
|
(20
|
)
|
|
|
33
|
|
EBITDA(b)
|
|
$
|
1,491
|
|
|
$
|
668
|
|
|
$
|
912
|
|
(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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
THREE MONTHS ENDED:
|
|
March 31, 2014
|
|
December 31, 2013
|
|
March 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
1,491
|
|
|
$
|
668
|
|
|
$
|
912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses on natural gas, oil and NGL derivatives
|
|
|
144
|
|
|
|
10
|
|
|
|
146
|
|
Restructuring and other termination costs
|
|
|
(7
|
)
|
|
|
45
|
|
|
|
133
|
|
Impairments of fixed assets and other
|
|
|
20
|
|
|
|
203
|
|
|
|
27
|
|
Net gains on sales of fixed assets
|
|
|
(23
|
)
|
|
|
(12
|
)
|
|
|
(49
|
)
|
Losses on investments
|
|
|
—
|
|
|
|
136
|
|
|
|
10
|
|
Net gains on sales of investments
|
|
|
(67
|
)
|
|
|
—
|
|
|
|
—
|
|
Losses on purchases of debt and extinguishment of other financing
|
|
|
—
|
|
|
|
123
|
|
|
|
—
|
|
Net income attributable to noncontrolling
interests
|
|
|
(41
|
)
|
|
|
(42
|
)
|
|
|
(44
|
)
|
Other
|
|
|
(2
|
)
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(a)
|
|
$
|
1,515
|
|
|
$
|
1,132
|
|
|
$
|
1,134
|
|
(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 MAY 7, 2014
|
|
Chesapeake periodically provides management guidance on certain
factors that affect the company’s future financial performance.
The primary changes from the company’s February 6, 2014, Outlook
are in italicized bold below.
|
|
Chesapeake Energy Corporation Consolidated Projections
|
|
|
|
|
|
Year Ending 12/31/2014
|
Production Growth (adjusted for 2013 asset sales)(a):
|
|
|
Liquids:
|
|
25 – 29%
|
Oil
|
|
8 – 12%
|
NGL(b)
|
|
58 – 63%
|
Natural gas
|
|
4 – 6%
|
Total Adjusted Production Growth
|
|
9 – 12%
|
Daily Equivalent Rate - mboe
|
|
690 – 710
|
NYMEX Price(c) (for calculation of realized hedging
effects only):
|
|
|
Oil - $/bbl
|
|
$95.92
|
Natural gas - $/mcf
|
|
$4.62
|
Estimated Realized Hedging Effects(d) (based on assumed
NYMEX prices above):
|
|
|
Oil - $/bbl
|
|
($6.15)
|
Natural gas - $/mcf
|
|
($0.31)
|
Estimated Gathering/Marketing/Transportation Differentials to NYMEX
Prices:
|
|
|
Oil - $/bbl
|
|
$3.25 – 5.25
|
NGL - $/bbl
|
|
$67.50 – 71.50
|
Natural gas - $/mcf
|
|
$1.60 – 1.70
|
Operating Costs per Boe of Projected Production:
|
|
|
Production expense
|
|
$4.25 – 4.75
|
Production taxes
|
|
$0.85 – 0.95
|
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
|
|
$1.20 – 1.30
|
Interest expense(f)
|
|
$0.75 – 0.85
|
Other ($ millions):
|
|
|
Marketing, gathering and compression net margin(g)
|
|
$50 – 75
|
Oilfield services net margin(g)
|
|
$200 – 250
|
Net income attributable to noncontrolling interests and other(h)
|
|
($160 – 190)
|
Book Tax Rate
|
|
37.5%
|
Weighted Average Shares Outstanding (in millions):
|
|
|
Basic
|
|
657 – 661
|
Diluted
|
|
767 – 771
|
Operating Cash Flow before Changes in Assets and Liabilities ($ in
millions) (i)(j)(k)
|
|
$5,800 – 6,000
|
Total Capital Expenditures ($ in millions)
|
|
$5,200 – 5,600
|
Capitalized interest, dividends and distributions ($ in millions)
|
|
$1,150 – 1,200
|
|
|
|
a) Growth ranges based on 2013 production of 634 mboe/day adjusted
for assets sales.
|
b) Assumes ethane recovery in the Utica and southern Marcellus to
fulfill Chesapeake’s pipeline commitments, no ethane recovery in
the Rockies and the Eagle Ford and partial ethane recovery in the
Mid-Continent.
|
c) NYMEX natural gas and oil prices have been updated for actual
contract prices through April and March, 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, LLC and CHK Cleveland Tonkawa, LLC.
|
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
$4.50 per mcf and production growth ranges as shown above.
|
k) The new guidance presentation we have adopted includes only cash
related hedging gains/losses and excludes noncash amortization.
Previously our Outlook guidance treated all realized hedging
gains/losses as cash and all unrealized gains/losses as noncash.
However, a portion of our realized hedging gains/losses actually
consists of noncash amortization from previously closed out hedges.
Please note that cash flow from operating activities on a GAAP basis
is unaffected by this presentation change.
|
|
|
|
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 May 1, 2014, the company had downside protection on approximately
64% of its remaining projected 2014 natural gas production at an average
price of $4.10 per mcf. Approximately 70% of the company's remaining
projected 2014 oil production had downside protection at an average
price of $94.32 per bbl.
The company’s natural gas hedging positions as of May 1, 2014, were as
follows:
|
|
|
|
|
|
|
|
|
|
Open Natural Gas Swaps; Gains (Losses) from Closed
|
Natural Gas Trades and Call Option Premiums
|
|
|
|
|
|
|
|
|
|
|
|
|
Open Swaps (bcf)
|
|
Avg. NYMEX Price of Open Swaps
|
|
Total Gains (Losses) from Closed Trades and Premiums for
Call Options ($ in millions)
|
Q2 2014
|
|
107
|
|
$
|
4.08
|
|
$
|
(12
|
)
|
Q3 2014
|
|
112
|
|
|
4.09
|
|
|
(15
|
)
|
Q4 2014
|
|
112
|
|
|
4.08
|
|
|
(21
|
)
|
Total Q2 - Q4 2014
|
|
331
|
|
$
|
4.08
|
|
$
|
(48
|
)
|
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
|
Q2 2014
|
|
51
|
|
$
|
3.57
|
|
$
|
4.09
|
|
$
|
4.38
|
Q3 2014
|
|
57
|
|
|
3.55
|
|
|
4.09
|
|
|
4.38
|
Q4 2014
|
|
71
|
|
|
3.49
|
|
|
4.11
|
|
|
4.37
|
Total Q2 - Q4 2014
|
|
179
|
|
$
|
3.53
|
|
$
|
4.10
|
|
$
|
4.38
|
Total 2015
|
|
207
|
|
$
|
3.37
|
|
$
|
4.29
|
|
$
|
4.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars
|
|
|
|
|
|
|
|
|
|
Open Collars (bcf)
|
|
Avg. NYMEX Bought Put Price
|
|
Avg. NYMEX Bought Put Price
|
Q2 2014
|
|
2
|
|
$4.51
|
|
$5.25
|
Q3 2014
|
|
6
|
|
4.51
|
|
5.25
|
Q4 2014
|
|
6
|
|
4.51
|
|
5.25
|
Total Q2 - Q4 2014
|
|
14
|
|
$4.51
|
|
$5.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
Q2 2014
|
|
45
|
|
$
|
(0.53
|
)
|
Q3 2014
|
|
46
|
|
$
|
(0.53
|
)
|
Q4 2014
|
|
20
|
|
$
|
(0.49
|
)
|
Total Q2 - Q4 2014
|
|
111
|
|
$
|
(0.52
|
)
|
Total 2015
|
|
31
|
|
$
|
(0.34
|
)
|
Total 2016 - 2022
|
|
8
|
|
$
|
(1.02
|
)
|
|
|
|
|
|
|
|
The company’s crude oil hedging positions as of May 1, 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)
|
Q2 2014
|
|
8,076
|
|
$
|
94.44
|
|
$
|
(46
|
)
|
Q3 2014
|
|
7,241
|
|
|
94.28
|
|
|
(48
|
)
|
Q4 2014
|
|
7,197
|
|
|
94.22
|
|
|
(49
|
)
|
Total Q2 - Q4 2014
|
|
22,514
|
|
$
|
94.32
|
|
$
|
(143
|
)
|
Total 2015
|
|
1,689
|
|
$
|
90.93
|
|
$
|
245
|
|
Total 2016 – 2022
|
|
0
|
|
|
—
|
|
$
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Written Call Options
|
|
|
|
|
|
|
|
|
Call Options (mbbls)
|
|
Avg. NYMEX Strike Price
|
Q2 2014
|
|
619
|
|
$
|
83.53
|
Q3 2014
|
|
626
|
|
|
83.53
|
Q4 2014
|
|
626
|
|
|
83.53
|
Total Q2 - Q4 2014
|
|
1,871
|
|
$
|
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
|
Q2 2014
|
|
91
|
|
$
|
6.00
|
Q3 2014
|
|
92
|
|
|
6.00
|
Q4 2014
|
|
92
|
|
|
6.00
|
Total Q2 - Q4 2014
|
|
275
|
|
$
|
6.00
|
|
|
|
|
|
|
Copyright Business Wire 2014