OKLAHOMA CITY, Nov. 4, 2015 /PRNewswire/ -- Chesapeake
Energy Corporation (NYSE:CHK) today reported financial and
operational results for the 2015 third quarter. Highlights
include:
- Production averaged approximately 667,000 boe per day, an
increase of 3% year over year, adjusted for asset
sales
- Adjusted net loss of $0.05
per fully diluted share and adjusted ebitda of $560 million
- 2015 total production guidance increased to 670 – 680
mboe per day
- 2015 production expense and general and administrative
expense guidance lowered significantly
- 2015 capital guidance reduced to $3.4 – $3.9
billion
Doug Lawler, Chesapeake's Chief Executive Officer,
commented, "The many actions that we have taken this quarter,
including executing new gas gathering agreements, amending our
revolving credit facility, reducing complexity and commitments and
lowering our business costs, have significantly increased
Chesapeake's ability to create
additional value. Our focus on optimizing base production and
continuing to generate efficiencies in the field drove a 3%
increase in production compared to last year, adjusted for asset
sales. In addition, the elimination of $200
million of annualized, controllable production and general
and administrative expenses represents another step in our
commitment to financial discipline."
Lawler continued, "We lowered our 2015 capital guidance to
$3.4 to $3.9 billion and are prepared
to execute on a significantly lower capital program in 2016. While
the current price environment presents many challenges for our
industry, we will continue focusing on our capital and operating
cost efficiency, enhancing our cash flow and financial flexibility
and optimizing our base production. The power of our people, the
strength of our portfolio and our operational leadership will
continue to create value for Chesapeake for the long term."
2015 Third Quarter Financial Results
For the 2015 third quarter, Chesapeake reported a net loss available to
common stockholders of $4.695
billion, or $7.08 per fully
diluted share, which compares to net income available to common
stockholders of $169 million, or
$0.26 per fully diluted share, in the
2014 third quarter. Items typically excluded by securities
analysts in their earnings estimates reduced 2015 third quarter net
income by approximately $4.612
billion on an after-tax basis and are presented on Page 12
of this release. The primary source of this reduction was a
noncash impairment of the carrying value of Chesapeake's oil and natural gas properties
largely resulting from significant decreases in the trailing
12-month average first-day-of-the-month oil and natural gas prices
as of September 30, 2015, compared to
June 30, 2015. Adjusting for
this and other items, the 2015 third quarter net loss available to
common stockholders was $83 million,
or $0.05 per fully diluted share,
which compares to adjusted net income available to common
stockholders of $251 million, or
$0.38 per fully diluted share, in the
2014 third quarter.
Adjusted ebitda was $560 million
in the 2015 third quarter, compared to $1.236 billion in the 2014 third quarter.
Operating cash flow was $476 million
in the 2015 third quarter, compared to $1.293 billion in the 2014 third quarter.
The year-over-year decreases in adjusted ebitda and operating cash
flow were primarily the result of lower realized oil, natural gas
and natural gas liquid (NGL) prices, partially offset by higher
realized hedging gains and lower production expenses, general and
administrative (G&A) expenses and production taxes.
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 – 17 of this
release.
2015 Third Quarter Average Daily Production of 667,000 Boe
Increased 3% Year Over Year, Adjusted for Asset Sales
Chesapeake's daily production
for the 2015 third quarter averaged approximately 667,000 barrels
of oil equivalent (boe), a year-over-year increase of 3% adjusted
for asset sales. Average daily production in the 2015 third
quarter consisted of approximately 114,100 barrels (bbls) of oil,
2.9 billion cubic feet (bcf) of natural gas and 76,200 bbls of NGL,
which represent year-over-year increases of 4%, 2% and 7%,
respectively, adjusted for asset sales. During the 2015 third
quarter, the company had average curtailed production of
approximately 51,000 boe per day. The company has increased its
total 2015 production guidance to 670,000 – 680,000 boe per day,
representing a 6% – 8% increase over 2014 results, adjusted for
asset sales.
Capital Spending and Cost Overview
Chesapeake's 2015 third quarter
drilling and completion capital expenditures decreased 41%
sequentially to approximately $467
million, and capital expenditures for leasehold, geological
and geophysical costs and other property, plant and equipment
remained flat at approximately $57
million, for a total of approximately $524 million. Total 2015 third quarter
capital expenditures of $623 million,
including capitalized interest of $99
million, decreased 35% and 59% compared to 2015 second
quarter and 2014 third quarter results, respectively, and are
detailed in the table below. For 2015, the company has reduced its
estimated total capital expenditures to $3.4 – $3.9
billion, compared to $3.5 –
$4.0 billion as previously
provided.
|
2015
|
2015
|
2014
|
Activity
Comparison
|
Q3
|
Q2
|
Q3
|
Average operated rig
count
|
18
|
26
|
69
|
Gross wells
completed
|
84
|
121
|
309
|
Gross wells
spud
|
81
|
109
|
296
|
Gross wells
connected
|
112
|
173
|
311
|
|
|
|
|
Type of Cost ($ in
millions)
|
|
|
|
Drilling and
completion costs
|
$467
|
$787
|
$1,241
|
Leasehold, G&G
and other PP&E
|
57
|
56
|
110
|
Subtotal capital
spending
|
$524
|
$843
|
$1,351
|
Capitalized
interest
|
99
|
114
|
170
|
Total capital
spending
|
$623
|
$957
|
$1,521
|
Chesapeake's focus on cost
discipline continued to generate reductions in production and
G&A expenses. Production expenses during the 2015 third
quarter were $4.09 per boe, while
G&A expenses (including stock-based compensation) during the
2015 third quarter were $0.79 per
boe. Combined production expenses and G&A expenses
(including stock-based compensation) during the 2015 third quarter
decreased 10% sequentially and 9% year over year.
A summary of the company's guidance for 2015 is provided in the
Outlook dated November 4, 2015,
beginning on Page 18.
Operational Results – Southern Division
Eagle Ford Shale (South
Texas): Eagle Ford net production averaged approximately
108 thousand barrels of oil equivalent (mboe) per day (234 gross
operated mboe per day) during the 2015 third quarter, an increase
of 3% sequentially. Average completed well costs to date in 2015
are $5.3 million with an average
completed lateral length of 6,000 feet and 21 frac stages, compared
to the full-year 2014 average completed well cost of $5.9 million with an average completed lateral
length of 5,850 feet and 18 frac stages. Chesapeake continues to realize significant
efficiencies with longer laterals and larger completions in the
area. Recent third quarter well results include the Rogers E-1H and
Faith San Pedro F-4H wells, which had completed lateral lengths of
12,488 and 13,151 feet, respectively, and reached peak 24-hour
production rates of 1,479 and 1,067 bbls of oil per day,
respectively. These two long-lateral wells have an average field
estimated completed well cost of $7.8
million each. The JEA Unit XIV LAS S 4H East Four Corners
well was also completed in the third quarter using an enhanced
design on a 4,611-foot completed lateral and reached a peak 24-hour
rate of 1,311 bbls of oil per day. The field estimated completed
well cost of this well is $4.8
million. The company placed 30 wells on production during
the 2015 third quarter, compared to 89 wells in the 2014 third
quarter. Chesapeake's operated rig
count in the Eagle Ford averaged three rigs in the 2015 third
quarter, and the company anticipates maintaining three operated
rigs through the end of the year.
Haynesville Shale and Bossier Shales (Northwest Louisiana): Haynesville net production averaged
approximately 636 million cubic feet of natural gas (mmcf) per day
(1.03 gross operated bcf per day) during the 2015 third quarter, a
decrease of 5% sequentially. Average completed well costs to date
in 2015 are $7.7 million with an
average completed lateral length of 5,000 feet and 14 frac stages,
compared to the full-year 2014 average completed well cost of
$8.4 million with an average
completed lateral length of 4,900 feet and 14 frac stages. The
company placed seven wells on production during the 2015 third
quarter, compared to 14 wells in the 2014 third quarter. Operated
rig count in the Haynesville
averaged six rigs in the 2015 third quarter, and the company
anticipates maintaining six operated rigs through the end of the
year.
Mid-Continent: Mississippian Lime (Northern Oklahoma): Mississippian Lime net
production averaged approximately 31 mboe per day (74 gross
operated mboe per day) during the 2015 third quarter, a decrease of
1% sequentially. Average completed well costs to date in 2015 are
$2.8 million with an average
completed lateral length of 4,500 feet and nine frac stages,
compared to the full-year 2014 average completed well cost of
$3.0 million with an average
completed lateral length of 4,450 feet and nine frac stages. During
the 2015 third quarter, the company drilled a record lateral length
of 9,395 feet in the JJJ 23-25-11 1H well, which is currently being
completed. Chesapeake also drilled
its first multi-lateral well in the Mississippian Lime. The Wilber
26-27-11 1H, which had dual laterals of 4,653 feet and 4,556 feet,
is currently being completed. The company placed 13 wells on
production during the 2015 third quarter, compared to 44 wells in
the 2014 third quarter. Operated rig count in the Mississippian
Lime averaged three rigs during the 2015 third quarter, and the
company has released all operated rigs in the area through the end
of the year.
Oklahoma STACK (Northwest and Central Oklahoma): The company has
identified multiple stacked liquids-rich opportunities on its
extensive Oklahoma STACK leasehold position, substantially all of
which is held by production. During the 2015 third quarter, the
company drilled its first two wells targeting the Meramec
formation, and is currently drilling a third well, with encouraging
results. The Rouce 4-17-10 1H, which
has a completed lateral of 9,350 feet, was recently placed on
production and has reached over 870 bbls of oil per day after three
days. The Wittrock 16-16-9 1H has been drilled with a lateral
length of 9,220 feet and is currently being completed. The Stangl
36-16-9 1H is currently drilling with a planned lateral length of
9,426 feet. The company intends to keep one operated rig in the
STACK area through the end of the year.
Operational Results – Northern Division
Utica Shale (Eastern
Ohio): Utica net
production averaged approximately 106 mboe per day (183 gross
operated mboe per day) during the 2015 third quarter, a decrease of
15% sequentially, as the company voluntarily curtailed
approximately 20 net mboe per day during the quarter as a result of
weak product pricing. During the 2015 fourth quarter, a new
regional pipeline is expected to be placed in-service, allowing the
company to move an additional 350 mmcf per day out of the basin and
greater access to Gulf Coast pricing. Average completed well costs
to date in 2015 are $7.7 million with
an average completed lateral length of 7,900 feet and 40 frac
stages, compared to the full-year 2014 average completed well cost
of $7.2 million with an average
completed lateral length of 6,200 feet and 29 frac stages. During
the 2015 third quarter, the company drilled a new record lateral
length in the Utica of 12,976
feet. Additionally, the average cycle time for Utica wells drilled in the third quarter was
9.9 days, with a record cycle time of 6.8 days. Operated rig count
in the Utica averaged two rigs in
the 2015 third quarter, and the company anticipates maintaining two
operated rigs through the end of the year.
Marcellus Shale (Northern Pennsylvania): Marcellus net
production averaged approximately 809 mmcf per day (1.77 gross
operated bcf per day) during the 2015 third quarter, a decrease of
1% sequentially. Chesapeake has
been voluntarily curtailing production from the area since the 2015
first quarter, primarily due to weak in-basin gas prices. The
company anticipates maintaining Marcellus curtailments for the
remainder of the year and actively managing its production through
the winter months. Average completed well costs to date in 2015 are
$6.4 million with an average
completed lateral length of 6,800 feet and 29 frac stages, compared
to the full-year 2014 average completed well cost of $7.5 million with an average completed lateral
length of 6,000 feet and 27 frac stages. Recent third quarter well
results include two tests of the Upper Marcellus formation located
in Bradford County, Pennsylvania,
which had completed lateral lengths of 5,600 feet and 4,800 feet,
respectively, and reached peak 24-hour production rates of
approximately 19,000 mcf per day and 17,000 mcf per day,
respectively. The company believes that these successful
completions in the Upper Marcellus could provide more than 1,000
potential new drilling locations. Operated rig count in the
Marcellus averaged one rig in the 2015 third quarter, and the
company anticipates maintaining one operated rig through the end of
the year.
Powder River Basin (PRB)
(Wyoming): PRB net production
averaged approximately 21 mboe per day (31 gross operated mboe per
day) during the 2015 third quarter, an increase of 5% sequentially.
Average completed well costs to date in 2015 are $10.6 million with an average completed lateral
length of 5,900 feet and 22 frac stages, compared to the full-year
2014 average completed well cost of $10.6
million with an average completed lateral length of 5,400
feet and 20 frac stages. Recent third quarter well results include
the Barton 32-34-67 USA A 1H,
which was placed on production in October with a completed lateral
length of 9,500 feet and reached a peak 24-hour production rate of
1,500 boe per day (85% black oil) from the Niobrara formation. Operated rig count in the
PRB averaged one rig in the 2015 third quarter, and the company has
released all operated rigs in the area through the end of the
year.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational
results during the 2015 third quarter, as compared to results in
prior periods.
|
|
Three Months
Ended
|
|
|
09/30/15
|
|
06/30/15
|
|
09/30/14
|
Oil equivalent
production (in mmboe)
|
|
61.3
|
|
63.9
|
|
66.8
|
Oil production (in
mmbbls)
|
|
10.5
|
|
10.8
|
|
10.9
|
Average realized oil
price ($/bbl)(a)
|
|
62.68
|
|
67.91
|
|
84.81
|
Oil as % of total
production
|
|
17
|
|
17
|
|
16
|
Natural gas
production (in bcf)
|
|
263.0
|
|
275.4
|
|
282.0
|
Average realized
natural gas price ($/mcf)(a)
|
|
1.14
|
|
1.01
|
|
2.09
|
Natural gas as % of
total production
|
|
72
|
|
72
|
|
71
|
NGL production (in
mmbbls)
|
|
7.0
|
|
7.2
|
|
8.8
|
Average realized NGL
price ($/bbl)(a)
|
|
(1.38)
|
|
1.90
|
|
22.95
|
NGL as % of total
production
|
|
11
|
|
11
|
|
13
|
Production expenses
($/boe)
|
|
(4.09)
|
|
(4.32)
|
|
(4.47)
|
Production taxes
($/boe)
|
|
(0.42)
|
|
(0.52)
|
|
(0.94)
|
General and
administrative costs ($/boe)(b)
|
|
(0.64)
|
|
(0.89)
|
|
(0.72)
|
Stock-based
compensation ($/boe)
|
|
(0.15)
|
|
(0.19)
|
|
(0.18)
|
DD&A of natural
gas and liquids properties ($/boe)
|
|
(7.95)
|
|
(9.39)
|
|
(10.31)
|
DD&A of other
assets ($/boe)
|
|
(0.51)
|
|
(0.52)
|
|
(0.55)
|
Interest expense
($/boe)(a)
|
|
(1.41)
|
|
(1.12)
|
|
(0.16)
|
Marketing, gathering
and compression net margin ($ in millions)(c)
|
|
58
|
|
209
|
|
(7)
|
Operating cash flow
($ in millions)(d)
|
|
476
|
|
572
|
|
1,293
|
Operating cash flow
($/boe)
|
|
7.76
|
|
8.95
|
|
19.37
|
Adjusted ebitda ($ in
millions)(e)
|
|
560
|
|
600
|
|
1,236
|
Adjusted ebitda
($/boe)
|
|
9.12
|
|
9.37
|
|
18.52
|
Net income (loss)
available to common stockholders ($ in millions)
|
|
(4,695)
|
|
(4,151)
|
|
169
|
Earnings (loss) per
share – diluted ($)
|
|
(7.08)
|
|
(6.27)
|
|
0.26
|
Adjusted net income
(loss) available to common stockholders ($ in
millions)(f)
|
|
(83)
|
|
(126)
|
|
251
|
Adjusted earnings
(loss) per share – diluted ($)
|
|
(0.05)
|
|
(0.11)
|
|
0.38
|
|
|
(a)
|
Includes the effects
of realized gains (losses) from hedging, but excludes the effects
of unrealized gains (losses) from hedging.
|
(b)
|
Excludes expenses
associated with stock-based compensation and restructuring and
other termination costs.
|
(c)
|
Includes revenue,
operating expenses and $70 million and $220 million of unrealized
gains on supply contract derivatives for the three months ended
September 30, 2015 and June 30, 2015, respectively. Excludes
depreciation and amortization of other assets.
|
(d)
|
Defined as cash flow
provided by operating activities before changes in assets and
liabilities.
|
(e)
|
Defined as net income
before interest expense, income taxes and depreciation, depletion
and amortization expense, as adjusted to remove the effects of
certain items detailed on Pages 16 – 17.
|
(f)
|
Defined as net income
available to common stockholders, as adjusted to remove the effects
of certain items detailed on Page 12.
|
2015 Third Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled for
Wednesday, November 4, 2015 at
9:00 am EST. The telephone number to
access the conference call is 913-312-6690 or toll-free
888-600-4885. The passcode for the call is 4959206.
We encourage those who would like to participate in the call to
place calls between 8:50 and 9:00 am
EST. For those unable to participate in the live conference
call, a replay will be available for audio playback at 12:00 pm EST on Wednesday,
November 4, 2015, and will run through 12:00 pm EST on Wednesday,
November 18, 2015. The number to access the conference call
replay is 719-457-0820 or toll-free
888-203-1112. The passcode for the replay is
4959206. The conference call will also be webcast live at
www.chk.com in the "Investors" section of the company's website.
The webcast of the conference will be available on the website for
one year.
Chesapeake Energy Corporation (NYSE:CHK) is the
second-largest producer of natural gas and the 12th 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 oil and natural gas assets onshore in the U.S.
The company also owns substantial marketing and compression
businesses. Further information is available at www.chk.com
where Chesapeake routinely posts
announcements, updates, events, investor information, presentations
and news releases.
This news release and the accompanying Outlook include
"forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements are statements
other than statements of historical fact. They include statements
that give our current expectations or forecasts of future events,
production and well connection forecasts, estimates of operating
costs, anticipated capital and operational efficiencies, planned
development drilling and expected drilling cost reductions, general
and administrative expenses, capital expenditures, the timing of
anticipated noncore asset sales and proceeds to be received
therefrom, projected cash flow and liquidity, our
ability to enhance our cash flow and financial flexibility, plans
and objectives for future operations (including our ability to
optimize base production and execute gas gathering agreements), the
ability of our employees, portfolio strength and operational
leadership to create long-term value, and the assumptions on which
such statements are based. Although we believe the expectations and
forecasts reflected in the forward-looking statements are
reasonable, we can give no assurance they will prove to have been
correct. They can be affected by inaccurate or changed assumptions
or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially
from expected results include those described under "Risk Factors"
in Item 1A of our annual report on Form 10-K and any updates to
those factors set forth in Chesapeake's subsequent quarterly reports on
Form 10-Q or current reports on Form 8-K (available at
http://www.chk.com/investors/sec-filings). These risk factors
include the volatility of oil, natural gas and NGL prices;
write-downs of our oil and natural gas carrying values due to
declines in prices; the availability of operating cash flow and
other funds to finance reserve replacement costs; our ability to
replace reserves and sustain production; uncertainties inherent in
estimating quantities of oil, natural gas 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; commodity
derivative activities resulting in lower prices realized on oil,
natural gas and NGL sales; the need to secure derivative
liabilities and the inability of counterparties to satisfy their
obligations; adverse developments or losses from pending or future
litigation and regulatory proceedings, including royalty claims;
the limitations our level of indebtedness may have on our financial
flexibility; charges incurred in response to market conditions and
in connection with actions to reduce financial leverage and
complexity; drilling and operating risks and resulting liabilities;
effects of environmental protection laws and regulation on our
business; legislative and regulatory initiatives further regulating
hydraulic fracturing; our need to secure adequate supplies of water
for our drilling operations and to dispose of or recycle the water
used; federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge
against commodity price fluctuations; impacts of potential
legislative and regulatory actions addressing climate change;
competition in the oil and gas exploration and production industry;
a deterioration in general economic, business or industry
conditions; negative public perceptions of our industry; limited
control over properties we do not operate; pipeline and gathering
system capacity constraints and transportation interruptions; cyber
attacks adversely impacting our operations; and interruption in
operations at our headquarters due to a catastrophic event.
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. Expected asset sales may not be completed in the
time frame anticipated or at all. 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.
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
|
Gordon
Pennoyer
|
(405)
935-8870
|
(405)
935-8878
|
ir@chk.com
|
media@chk.com
|
CHESAPEAKE ENERGY
CORPORATION
|
|
|
|
|
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
($ in millions,
except per share data)
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months
Ended
September 30,
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL
|
|
$
|
880
|
|
$
|
2,341
|
|
$
|
2,693
|
|
|
$
|
5,812
|
|
Marketing, gathering
and compression
|
|
2,013
|
|
3,362
|
|
5,993
|
|
|
9,543
|
|
Oilfield
services
|
|
—
|
|
—
|
|
—
|
|
|
546
|
|
Total
Revenues
|
|
2,893
|
|
5,703
|
|
8,686
|
|
|
15,901
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
251
|
|
298
|
|
826
|
|
|
868
|
|
Production
taxes
|
|
25
|
|
62
|
|
87
|
|
|
185
|
|
Marketing, gathering
and compression
|
|
1,955
|
|
3,369
|
|
5,751
|
|
|
9,515
|
|
Oilfield
services
|
|
—
|
|
—
|
|
—
|
|
|
431
|
|
General and
administrative
|
|
49
|
|
60
|
|
174
|
|
|
229
|
|
Restructuring and
other termination costs
|
|
53
|
|
(14)
|
|
39
|
|
|
12
|
|
Provision for legal
contingencies
|
|
—
|
|
100
|
|
359
|
|
|
100
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
488
|
|
688
|
|
1,773
|
|
|
1,977
|
|
Depreciation and
amortization of other assets
|
|
31
|
|
37
|
|
100
|
|
|
194
|
|
Impairment of oil and
natural gas properties
|
|
5,416
|
|
—
|
|
15,407
|
|
|
—
|
|
Impairments of fixed
assets and other
|
|
79
|
|
15
|
|
167
|
|
|
75
|
|
Net (gains) losses on
sales of fixed assets
|
|
(1)
|
|
(86)
|
|
3
|
|
|
(201)
|
|
Total Operating
Expenses
|
|
8,346
|
|
4,529
|
|
24,686
|
|
|
13,385
|
|
INCOME (LOSS) FROM
OPERATIONS
|
|
(5,453)
|
|
1,174
|
|
(16,000)
|
|
|
2,516
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(88)
|
|
(17)
|
|
(210)
|
|
|
(82)
|
|
Losses on
investments
|
|
(33)
|
|
(27)
|
|
(57)
|
|
|
(72)
|
|
Net gain on sales of
investments
|
|
—
|
|
—
|
|
—
|
|
|
67
|
|
Losses on purchases
of debt
|
|
—
|
|
—
|
|
—
|
|
|
(195)
|
|
Other income
(expense)
|
|
(2)
|
|
(1)
|
|
3
|
|
|
12
|
|
Total Other
Expense
|
|
(123)
|
|
(45)
|
|
(264)
|
|
|
(270)
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
|
(5,576)
|
|
1,129
|
|
(16,264)
|
|
|
2,246
|
|
INCOME TAX EXPENSE
(BENEFIT):
|
|
|
|
|
|
|
|
|
Current income
taxes
|
|
—
|
|
2
|
|
(6)
|
|
|
10
|
|
Deferred income
taxes
|
|
(937)
|
|
435
|
|
(3,808)
|
|
|
849
|
|
Total Income Tax
Expense (Benefit)
|
|
(937)
|
|
437
|
|
(3,814)
|
|
|
859
|
|
NET INCOME
(LOSS)
|
|
(4,639)
|
|
692
|
|
(12,450)
|
|
|
1,387
|
|
Net income
attributable to noncontrolling interests
|
|
(13)
|
|
(30)
|
|
(50)
|
|
|
(110)
|
|
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
|
|
(4,652)
|
|
662
|
|
(12,500)
|
|
|
1,277
|
|
Preferred stock
dividends
|
|
(43)
|
|
(43)
|
|
(128)
|
|
|
(128)
|
|
Repurchase of
preferred shares of CHK Utica
|
|
—
|
|
(447)
|
|
—
|
|
|
(447)
|
|
Earnings allocated to
participating securities
|
|
—
|
|
(3)
|
|
—
|
|
|
(15)
|
|
NET INCOME (LOSS)
AVAILABLE TO COMMON STOCKHOLDERS
|
|
$
|
(4,695)
|
|
$
|
169
|
|
$
|
(12,628)
|
|
|
$
|
687
|
|
EARNINGS (LOSS)
PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(7.08)
|
|
$
|
0.26
|
|
|
$
|
(19.07)
|
|
|
$
|
1.04
|
|
Diluted
|
|
$
|
(7.08)
|
|
$
|
0.26
|
|
|
$
|
(19.07)
|
|
|
$
|
1.04
|
|
WEIGHTED AVERAGE
COMMON AND COMMON
EQUIVALENT SHARES
OUTSTANDING (in millions):
|
|
|
|
|
|
|
|
|
Basic
|
|
663
|
|
660
|
|
|
662
|
|
|
659
|
|
Diluted
|
|
663
|
|
660
|
|
|
662
|
|
|
659
|
|
CHESAPEAKE ENERGY
CORPORATION
|
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
($ in
millions)
|
(unaudited)
|
|
|
|
|
|
|
|
September 30,
2015
|
|
December 31,
2014
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
1,759
|
|
|
$
|
4,108
|
|
Other current
assets
|
|
1,820
|
|
|
3,360
|
|
Total Current
Assets
|
|
3,579
|
|
|
7,468
|
|
|
|
|
|
|
Property and
equipment, (net)
|
|
16,959
|
|
|
32,515
|
|
Other
assets
|
|
748
|
|
|
768
|
|
Total
Assets
|
|
$
|
21,286
|
|
|
$
|
40,751
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
4,557
|
|
|
$
|
5,863
|
|
Long-term debt, net
of discounts
|
|
10,674
|
|
|
11,154
|
|
Other long-term
liabilities
|
|
935
|
|
|
1,344
|
|
Deferred income tax
liabilities
|
|
574
|
|
|
4,185
|
|
Total
Liabilities
|
|
16,740
|
|
|
22,546
|
|
|
|
|
|
|
Preferred
stock
|
|
3,062
|
|
|
3,062
|
|
Noncontrolling
interests
|
|
264
|
|
|
1,302
|
|
Common stock and
other stockholders' equity
|
|
1,220
|
|
|
13,841
|
|
Total
Equity
|
|
4,546
|
|
|
18,205
|
|
|
|
|
|
|
Total Liabilities and
Equity
|
|
$
|
21,286
|
|
|
$
|
40,751
|
|
|
|
|
|
|
Common Shares
Outstanding (in millions)
|
|
663
|
|
|
663
|
|
CHESAPEAKE ENERGY
CORPORATION
|
CAPITALIZATION
|
($ in
millions)
|
(unaudited)
|
|
|
|
September 30,
2015
|
|
December 31,
2014
|
|
|
|
|
|
Total debt, net of
unrestricted cash
|
|
$
|
9,808
|
|
|
$
|
7,427
|
|
Preferred
stock
|
|
3,062
|
|
|
3,062
|
|
Noncontrolling
interests(a)
|
|
264
|
|
|
1,302
|
|
Common stock and
other stockholders' equity
|
|
1,220
|
|
|
13,841
|
|
Total
|
|
$
|
14,354
|
|
|
$
|
25,632
|
|
|
|
|
|
|
Total net debt to
capitalization ratio
|
|
68
|
%
|
|
29
|
%
|
|
|
|
|
|
|
|
(a)
Includes third-party ownership as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake Granite Wash Trust
|
|
$
|
264
|
|
|
$
|
287
|
|
CHK
Cleveland Tonkawa, L.L.C. (1)
|
|
—
|
|
|
1,015
|
|
Total
|
|
$
|
264
|
|
|
$
|
1,302
|
|
(1) Repurchase of noncontrolling interest of CHK
Cleveland Tonkawa occurred in August 2015.
|
CHESAPEAKE ENERGY
CORPORATION
|
SUPPLEMENTAL
DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND
INTEREST EXPENSE
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months
Ended
September 30,
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Net
Production:
|
|
|
|
|
|
|
|
|
Oil
(mmbbl)
|
|
10.5
|
|
10.9
|
|
32.3
|
|
31.1
|
Natural gas
(bcf)
|
|
263.0
|
|
282.0
|
|
802.2
|
|
813.4
|
NGL
(mmbbl)
|
|
7.0
|
|
8.8
|
|
21.0
|
|
24.1
|
Oil equivalent
(mmboe)
|
|
61.3
|
|
66.8
|
|
187.0
|
|
190.7
|
|
|
|
|
|
|
|
|
|
Oil, natural gas
and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
434
|
|
$
|
1,005
|
|
$
|
1,442
|
|
$
|
2,933
|
Oil derivatives –
realized gains (losses)(a)
|
|
224
|
|
(77)
|
|
641
|
|
(288)
|
Oil derivatives –
unrealized gains (losses)(a)
|
|
(100)
|
|
456
|
|
(444)
|
|
354
|
Total Oil
Sales
|
|
558
|
|
1,384
|
|
1,639
|
|
2,999
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
228
|
|
569
|
|
859
|
|
2,324
|
Natural gas
derivatives – realized gains (losses)(a)
|
|
70
|
|
19
|
|
341
|
|
(221)
|
Natural gas
derivatives – unrealized gains (losses)(a)
|
|
33
|
|
166
|
|
(198)
|
|
125
|
Total Natural Gas
Sales
|
|
331
|
|
754
|
|
1,002
|
|
2,228
|
|
|
|
|
|
|
|
|
|
NGL sales
|
|
(9)
|
|
203
|
|
52
|
|
585
|
Total NGL
Sales
|
|
(9)
|
|
203
|
|
52
|
|
585
|
Total Oil, Natural
Gas and NGL Sales
|
|
$
|
880
|
|
$
|
2,341
|
|
$
|
2,693
|
|
$
|
5,812
|
|
|
|
|
|
|
|
|
|
Average Sales
Price – excluding gains (losses) on derivatives:
|
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
41.25
|
|
$
|
91.87
|
|
$
|
44.57
|
|
$
|
94.28
|
Natural gas ($ per
mcf)
|
|
$
|
0.87
|
|
$
|
2.02
|
|
$
|
1.07
|
|
$
|
2.86
|
NGL ($ per
bbl)
|
|
$
|
(1.38)
|
|
$
|
22.95
|
|
$
|
2.46
|
|
$
|
24.31
|
Oil equivalent ($ per
boe)
|
|
$
|
10.63
|
|
$
|
26.62
|
|
$
|
12.57
|
|
$
|
30.63
|
|
|
|
|
|
|
|
|
|
Average Sales
Price – including realized gains (losses) on
derivatives:
|
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
62.68
|
|
$
|
84.81
|
|
$
|
64.40
|
|
$
|
85.04
|
Natural gas ($ per
mcf)
|
|
$
|
1.14
|
|
$
|
2.09
|
|
$
|
1.50
|
|
$
|
2.59
|
NGL ($ per
bbl)
|
|
$
|
(1.38)
|
|
$
|
22.95
|
|
$
|
2.46
|
|
$
|
24.31
|
Oil equivalent ($ per
boe)
|
|
$
|
15.45
|
|
$
|
25.74
|
|
$
|
17.83
|
|
$
|
27.96
|
|
|
|
|
|
|
|
|
|
Interest Expense
($ in millions):
|
|
|
|
|
|
|
|
|
Interest(b)
|
|
$
|
88
|
|
$
|
15
|
|
$
|
222
|
|
$
|
132
|
Derivatives –
realized (gains) losses(c)
|
|
(2)
|
|
(4)
|
|
(4)
|
|
(9)
|
Derivatives –
unrealized (gains) losses(c)
|
|
2
|
|
6
|
|
(8)
|
|
(41)
|
Total Interest
Expense
|
|
$
|
88
|
|
$
|
17
|
|
$
|
210
|
|
$
|
82
|
|
|
(a)
|
Realized gains and
losses include the following items: (i) settlements of
nondesignated derivatives related to current period production
revenues, (ii) prior period settlements for option premiums and for
early-terminated derivatives originally scheduled to settle against
current period production revenues, and (iii) gains and losses
related to de-designated cash flow hedges originally designated to
settle against current period production revenues. Unrealized
gains and losses include the change in fair value of open
derivatives scheduled to settle against future period production
revenues offset by amounts reclassified as realized gains and
losses during the period. Although we no longer designate our
derivatives as cash flow hedges for accounting purposes, we believe
these definitions are useful to management and investors in
determining the effectiveness of our price risk management
program.
|
(b)
|
Net of amounts
capitalized.
|
(c)
|
Realized (gains)
losses include settlements related to the current period interest
accrual and the effect of (gains) losses on early termination
trades. Unrealized (gains) losses include changes in the fair
value of open interest rate derivatives offset by amounts
reclassified to realized (gains) losses during the
period.
|
CHESAPEAKE ENERGY
CORPORATION
|
CONDENSED
CONSOLIDATED CASH FLOW DATA
|
($ in
millions)
|
(unaudited)
|
|
|
|
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
Beginning
cash
|
|
$
|
2,051
|
|
|
$
|
1,462
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
318
|
|
|
1,184
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(528)
|
|
|
(1,189)
|
|
Acquisitions of
proved and unproved properties(b)
|
|
(141)
|
|
|
(667)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
174
|
|
|
475
|
|
Additions to other
property and equipment
|
|
(21)
|
|
|
(25)
|
|
Cash paid to purchase
leased rigs and compressors
|
|
—
|
|
|
(52)
|
|
Proceeds from sales
of other property and equipment
|
|
73
|
|
|
251
|
|
Additions to
investments
|
|
(2)
|
|
|
(9)
|
|
Decrease in
restricted cash
|
|
52
|
|
|
37
|
|
Other
|
|
—
|
|
|
(2)
|
|
Net cash used in
investing activities
|
|
(393)
|
|
|
(1,181)
|
|
|
|
|
|
|
Net cash used in
financing activities
|
|
(217)
|
|
|
(1,375)
|
|
Change in cash and
cash equivalents
|
|
(292)
|
|
|
(1,372)
|
|
Ending
cash
|
|
$
|
1,759
|
|
|
$
|
90
|
|
|
|
(a)
|
Includes capitalized
interest of $3 million and $11 million for the three months ended
September 30, 2015 and 2014, respectively.
|
(b)
|
Includes capitalized
interest of $93 million and $135 million for the three months ended
September 30, 2015 and 2014, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
|
CONDENSED
CONSOLIDATED CASH FLOW DATA
|
($ in
millions)
|
(unaudited)
|
|
|
|
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
Beginning
cash
|
|
$
|
4,108
|
|
|
$
|
837
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
1,055
|
|
|
3,805
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(2,696)
|
|
|
(3,185)
|
|
Acquisitions of
proved and unproved properties(b)
|
|
(407)
|
|
|
(1,023)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
188
|
|
|
723
|
|
Additions to other
property and equipment
|
|
(114)
|
|
|
(201)
|
|
Cash paid to purchase
leased rigs and compressors
|
|
—
|
|
|
(474)
|
|
Proceeds from sales
of other property and equipment
|
|
80
|
|
|
964
|
|
Additions to
investments
|
|
(8)
|
|
|
(14)
|
|
Proceeds from sales
of investments
|
|
—
|
|
|
239
|
|
Decrease in
restricted cash
|
|
52
|
|
|
37
|
|
Other
|
|
—
|
|
|
(4)
|
|
Net cash used in
investing activities
|
|
(2,905)
|
|
|
(2,938)
|
|
|
|
|
|
|
Net cash used in
financing activities
|
|
(499)
|
|
|
(1,614)
|
|
Change in cash and
cash equivalents
|
|
(2,349)
|
|
|
(747)
|
|
Ending
cash
|
|
$
|
1,759
|
|
|
$
|
90
|
|
|
|
(a)
|
Includes capitalized
interest of $21 million and $40 million for the nine months ended
September 30, 2015 and 2014, respectively.
|
(b)
|
Includes capitalized
interest of $305 million and $433 million for the nine months ended
September 30, 2015 and 2014, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
|
RECONCILIATION OF
ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
|
($ in millions,
except per share data)
|
(unaudited)
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2015
|
|
June 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
|
|
Net income (loss)
available to common stockholders
|
|
$
|
(4,695)
|
|
$
|
(4,151)
|
|
$
|
169
|
|
|
|
|
|
|
|
Adjustments, net
of tax:
|
|
|
|
|
|
|
Unrealized (gains)
losses on commodity derivatives
|
|
58
|
|
220
|
|
(384)
|
Unrealized gains on
supply contract derivatives
|
|
(58)
|
|
(161)
|
|
—
|
Restructuring and
other termination costs
|
|
44
|
|
(3)
|
|
(9)
|
Provision for legal
contingencies
|
|
—
|
|
244
|
|
62
|
Impairment of oil and
natural gas properties
|
|
4,506
|
|
3,666
|
|
—
|
Impairments of fixed
assets and other
|
|
66
|
|
61
|
|
9
|
Net (gains) losses on
sales of fixed assets
|
|
(1)
|
|
1
|
|
(54)
|
Repurchase of
preferred shares of CHK Utica
|
|
—
|
|
—
|
|
447
|
Other
|
|
(3)
|
|
(3)
|
|
11
|
Adjusted net
income (loss) available to common
stockholders(a)
|
|
$
|
(83)
|
|
$
|
(126)
|
|
$
|
251
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
43
|
|
43
|
|
43
|
Earnings allocated to
participating securities
|
|
—
|
|
—
|
|
3
|
Total adjusted net
income (loss) attributable to Chesapeake
|
|
$
|
(40)
|
|
$
|
(83)
|
|
$
|
297
|
|
|
|
|
|
|
|
Weighted average
fully diluted shares outstanding
(in
millions)(b)
|
|
777
|
|
777
|
|
776
|
|
|
|
|
|
|
|
Adjusted earnings
(loss) per share assuming dilution(a)
|
|
$
|
(0.05)
|
|
$
|
(0.11)
|
|
$
|
0.38
|
|
|
(a)
|
Adjusted net income
and adjusted earnings per share assuming dilution are not measures
of financial performance under accounting principles generally
accepted in the United States (GAAP), and should not be considered
as an alternative to net income available to common stockholders or
diluted earnings per share. 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 GAAP because:
|
|
(i)
|
Management uses
adjusted net income available to common stockholders to evaluate
the company's operational trends and performance relative to other
oil and natural gas 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)
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
Net income (loss)
available to common stockholders
|
|
$
|
(12,628)
|
|
$
|
687
|
|
|
|
|
|
Adjustments, net
of tax:
|
|
|
|
|
Unrealized (gains)
losses on commodity derivatives
|
|
486
|
|
(324)
|
Unrealized gains on
supply contract derivatives
|
|
(222)
|
|
—
|
Restructuring and
other termination costs
|
|
30
|
|
7
|
Provision for legal
contingencies
|
|
275
|
|
62
|
Impairment of oil and
natural gas properties
|
|
11,794
|
|
—
|
Impairments of fixed
assets and other
|
|
128
|
|
46
|
Net (gains) losses on
sales of fixed assets
|
|
2
|
|
(125)
|
Impairments of
investments
|
|
—
|
|
3
|
Net gain on sales of
investments
|
|
—
|
|
(42)
|
Losses on purchases
of debt
|
|
—
|
|
121
|
Repurchase of
preferred shares of CHK Utica
|
|
—
|
|
447
|
Tax rate
adjustment
|
|
(17)
|
|
—
|
Other
|
|
(10)
|
|
5
|
Adjusted net
income (loss) available to common
stockholders(a)
|
|
$
|
(162)
|
|
$
|
887
|
|
|
|
|
|
Preferred stock
dividends
|
|
128
|
|
128
|
Earnings allocated to
participating securities
|
|
—
|
|
15
|
Total adjusted net
income (loss) attributable to Chesapeake
|
|
$
|
(34)
|
|
$
|
1,030
|
|
|
|
|
|
Weighted average
fully diluted shares outstanding (in
millions)(b)
|
|
776
|
|
776
|
|
|
|
|
|
Adjusted earnings
(loss) per share assuming dilution(a)
|
|
$
|
(0.04)
|
|
$
|
1.33
|
|
|
(a)
|
Adjusted net income
and adjusted earnings per share assuming dilution are not measures
of financial performance under accounting principles generally
accepted in the United States (GAAP), and should not be considered
as an alternative to net income available to common stockholders or
diluted earnings per share. 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 GAAP because:
|
|
(i)
|
Management uses
adjusted net income available to common stockholders to evaluate
the company's operational trends and performance relative to other
oil and natural gas 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:
|
|
September
30,
2015
|
|
June
30,
2015
|
|
September
30,
2014
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
318
|
|
$
|
314
|
|
$
|
1,184
|
Changes in assets and
liabilities
|
|
158
|
|
258
|
|
109
|
OPERATING CASH
FLOW(a)
|
|
$
|
476
|
|
$
|
572
|
|
$
|
1,293
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2015
|
|
June 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
|
|
NET INCOME
(LOSS)
|
|
$
|
(4,639)
|
|
$
|
(4,090)
|
|
$
|
692
|
Interest
expense
|
|
88
|
|
71
|
|
17
|
Income tax expense
(benefit)
|
|
(937)
|
|
(1,506)
|
|
437
|
Depreciation and
amortization of other assets
|
|
31
|
|
34
|
|
37
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
488
|
|
601
|
|
688
|
EBITDA(b)
|
|
$
|
(4,969)
|
|
$
|
(4,890)
|
|
$
|
1,871
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2015
|
|
June 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
318
|
|
$
|
314
|
|
$
|
1,184
|
Changes in assets and
liabilities
|
|
158
|
|
258
|
|
109
|
Interest expense, net
of unrealized gains (losses) on derivatives
|
|
86
|
|
71
|
|
11
|
Gains (losses) on
commodity derivatives, net
|
|
227
|
|
(48)
|
|
564
|
Gains on supply
contract derivatives, net
|
|
70
|
|
220
|
|
—
|
Cash (receipts)
payments on oil, natural gas and NGL derivative settlements,
net
|
|
(223)
|
|
(223)
|
|
34
|
Stock-based
compensation
|
|
(18)
|
|
(20)
|
|
(19)
|
Restructuring and
other termination costs
|
|
(53)
|
|
4
|
|
42
|
Provision for legal
contingencies
|
|
—
|
|
(334)
|
|
(100)
|
Impairment of oil and
natural gas properties
|
|
(5,416)
|
|
(5,015)
|
|
—
|
Impairments of fixed
assets and other
|
|
(78)
|
|
(79)
|
|
(15)
|
Net gains (losses) on
sales of fixed assets
|
|
1
|
|
(1)
|
|
86
|
Losses on
investments
|
|
(33)
|
|
(17)
|
|
(27)
|
Other
items
|
|
(8)
|
|
(20)
|
|
2
|
EBITDA(b)
|
|
$
|
(4,969)
|
|
$
|
(4,890)
|
|
$
|
1,871
|
(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 an oil and
natural gas company's ability to generate cash that is used to
internally fund exploration and development activities and to
service debt. This measure is widely used by investors and
rating agencies in the valuation, comparison, rating and investment
recommendations of companies within the oil and natural gas
exploration and production industry. Operating cash flow is
not a measure of financial performance under GAAP and should not be
considered as an alternative to cash flows from operating,
investing or financing activities as an indicator of cash flows, or
as a measure of liquidity.
|
(b)
|
Ebitda represents net
income before interest expense, income taxes, and depreciation,
depletion and amortization expense. Ebitda is presented as a
supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information
regarding our ability to meet our future debt service, capital
expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of
companies. Ebitda is also a financial measurement that, with
certain negotiated adjustments, is reported to our lenders pursuant
to our bank credit agreements and is used in the financial
covenants in our bank credit agreements. Ebitda is not a
measure of financial performance under GAAP. Accordingly, it
should not be considered as a substitute for net income, income
from operations or cash flow provided by operating activities
prepared in accordance with GAAP.
|
CHESAPEAKE ENERGY
CORPORATION
|
RECONCILIATION OF
OPERATING CASH FLOW AND EBITDA
|
($ in
millions)
|
(unaudited)
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
1,055
|
|
$
|
3,805
|
Changes in assets and
liabilities
|
|
877
|
|
348
|
OPERATING CASH
FLOW(a)
|
|
$
|
1,932
|
|
$
|
4,153
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
NET INCOME
(LOSS)
|
|
$
|
(12,450)
|
|
$
|
1,387
|
Interest
expense
|
|
210
|
|
82
|
Income tax expense
(benefit)
|
|
(3,814)
|
|
859
|
Depreciation and
amortization of other assets
|
|
100
|
|
194
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
1,773
|
|
1,977
|
EBITDA(b)
|
|
$
|
(14,181)
|
|
$
|
4,499
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
1,055
|
|
$
|
3,805
|
Changes in assets and
liabilities
|
|
877
|
|
348
|
Interest expense, net
of unrealized gains (losses) on derivatives
|
|
218
|
|
123
|
Gains (losses) on
commodity derivatives, net
|
|
340
|
|
(30)
|
Gains on supply
contract derivatives, net
|
|
290
|
|
—
|
Cash (receipts)
payments on oil, natural gas and NGL derivative settlements,
net
|
|
(859)
|
|
352
|
Stock-based
compensation
|
|
(61)
|
|
(59)
|
Restructuring and
other termination costs
|
|
(39)
|
|
18
|
Provision for legal
contingencies
|
|
(359)
|
|
(100)
|
Impairment of oil and
natural gas properties
|
|
(15,407)
|
|
—
|
Impairments of fixed
assets and other
|
|
(159)
|
|
(44)
|
Net gains (losses) on
sales of fixed assets
|
|
(3)
|
|
201
|
Losses on
investments
|
|
(57)
|
|
(72)
|
Net gain on sales of
investments
|
|
—
|
|
67
|
Losses on purchases
of debt
|
|
—
|
|
(61)
|
Other
items
|
|
(17)
|
|
(49)
|
EBITDA(b)
|
|
$
|
(14,181)
|
|
$
|
4,499
|
(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 an oil and
natural gas company's ability to generate cash that is used to
internally fund exploration and development activities and to
service debt. This measure is widely used by investors and
rating agencies in the valuation, comparison, rating and investment
recommendations of companies within the oil and natural gas
exploration and production industry. Operating cash flow is
not a measure of financial performance under GAAP and should not be
considered as an alternative to cash flows from operating,
investing or financing activities as an indicator of cash flows, or
as a measure of liquidity.
|
(b)
|
Ebitda represents net
income before interest expense, income taxes, and depreciation,
depletion and amortization expense. Ebitda is presented as a
supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information
regarding our ability to meet our future debt service, capital
expenditures and working capital requirements. This measure
is widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of
companies. Ebitda is also a financial measurement that, with
certain negotiated adjustments, is reported to our lenders pursuant
to our bank credit agreements and is used in the financial
covenants in our bank credit agreements. Ebitda is not a
measure of financial performance under GAAP. Accordingly, it
should not be considered as a substitute for net income, income
from operations or cash flow provided by operating activities
prepared in accordance with GAAP.
|
CHESAPEAKE ENERGY
CORPORATION
|
RECONCILIATION OF
ADJUSTED EBITDA
|
($ in
millions)
|
(unaudited)
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2015
|
|
June 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
(4,969)
|
|
$
|
(4,890)
|
|
$
|
1,871
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
67
|
|
301
|
|
(622)
|
Unrealized gains on
supply contract derivatives
|
|
(70)
|
|
(220)
|
|
—
|
Restructuring and
other termination costs
|
|
53
|
|
(4)
|
|
(14)
|
Provision for legal
contingencies
|
|
—
|
|
334
|
|
100
|
Impairment of oil and
natural gas properties
|
|
5,416
|
|
5,015
|
|
—
|
Impairments of fixed
assets and other
|
|
79
|
|
84
|
|
15
|
Net (gains) losses on
sales of fixed assets
|
|
(1)
|
|
1
|
|
(86)
|
Net income
attributable to noncontrolling interests
|
|
(13)
|
|
(18)
|
|
(30)
|
Other
|
|
(2)
|
|
(3)
|
|
2
|
|
|
|
|
|
|
|
Adjusted
EBITDA(a)
|
|
$
|
560
|
|
$
|
600
|
|
$
|
1,236
|
CHESAPEAKE ENERGY
CORPORATION
|
RECONCILIATION OF
ADJUSTED EBITDA
|
($ in
millions)
|
(unaudited)
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2015
|
|
September 30,
2014
|
|
|
|
|
|
EBITDA
|
|
$
|
(14,181)
|
|
$
|
4,499
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
642
|
|
(479)
|
Unrealized gains on
supply contract derivatives
|
|
(290)
|
|
—
|
Restructuring and
other termination costs
|
|
39
|
|
12
|
Provision for legal
contingencies
|
|
359
|
|
100
|
Impairment of oil and
natural gas properties
|
|
15,407
|
|
—
|
Impairments of fixed
assets and other
|
|
167
|
|
75
|
Net (gains) losses on
sales of fixed assets
|
|
3
|
|
(201)
|
Impairments of
investments
|
|
—
|
|
5
|
Net gains on sales of
investments
|
|
—
|
|
(67)
|
Losses on purchases
of debt
|
|
—
|
|
195
|
Net income
attributable to noncontrolling interests
|
|
(50)
|
|
(110)
|
Other
|
|
(9)
|
|
—
|
|
|
|
|
|
Adjusted
EBITDA(a)
|
|
$
|
2,087
|
|
$
|
4,029
|
|
|
(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 oil and natural gas 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.
|
Accordingly, adjusted EBITDA 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
MANAGEMENT'S OUTLOOK AS OF NOVEMBER 4,
2015
Chesapeake periodically
provides management guidance on certain factors that affect the
company's future financial performance. Changes from the
company's August 5, 2015 Outlook are
italicized bold below.
|
Year
Ending
12/31/2015
|
Adjusted Production
Growth(a)
|
6% –
8%
|
Absolute
Production
|
|
Liquids -
mbbls
|
67.5 –
69.5
|
Oil -
mbbls
|
41.5 –
42.5
|
NGL(b) -
mbbls
|
26.0 –
27.0
|
Natural gas -
bcf
|
1,060 –
1,070
|
Total absolute
production - mmboe
|
244 –
249
|
Absolute daily rate -
mboe
|
670 –
680
|
Estimated Realized
Hedging Effects(c) (based on 10/31/15 strip
prices):
|
|
Oil -
$/bbl
|
$20.80
|
Natural gas -
$/mcf
|
$0.41
|
Estimated
Basis/Gathering/Marketing/Transportation Differentials to NYMEX
Prices:
|
|
Oil -
$/bbl
|
$6.00 –
8.00
|
Natural gas -
$/mcf
|
$1.65 –
1.85
|
NGL -
$/bbl
|
$48.00 –
50.00
|
Fourth quarter
minimum volume commitment (MVC) estimate ($ in millions)
|
($160) –
(180)
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$4.25 –
4.50
|
Production
taxes
|
$0.45 –
0.55
|
General and
administrative(d)
|
$0.75 –
0.85
|
Stock-based
compensation (noncash)
|
$0.15 –
0.20
|
DD&A of natural
gas and liquids assets
|
$8.00 –
9.00
|
Depreciation of other
assets
|
$0.50 –
0.60
|
Interest
expense(e)
|
$1.20 –
1.30
|
Other ($
millions):
|
|
Marketing, gathering
and compression net margin(f)
|
($40 – 60)
|
Net income
attributable to noncontrolling interests and
other(g)
|
($60 – 65)
|
Book Tax
Rate
|
20% –
30%
|
Capital Expenditures
($ in millions)(h)
|
$3,000 –
3,500
|
Capitalized Interest
($ in millions)
|
$425
|
Total Capital
Expenditures ($ in millions)
|
$3,425 –
3,925
|
|
|
(a)
|
Based on 2014
production of 618 mboe per day adjusted for 2014 sales and the sale
of the Cleveland Tonkawa asset in 2015.
|
(b)
|
Assumes ethane
recovery in the Utica to fulfill Chesapeake's pipeline commitments,
no ethane recovery in the Powder River Basin and partial ethane
recovery in the Mid-Continent and Eagle Ford.
|
(c)
|
Includes expected
settlements for commodity derivatives adjusted for option
premiums. For derivatives closed early, settlements are
reflected in the period of original contract expiration.
|
(d)
|
Excludes expenses
associated with stock-based compensation.
|
(e)
|
Excludes unrealized
gains (losses) on interest rate derivatives.
|
(f)
|
Includes revenue and
operating expenses. Excludes depreciation and amortization of other
assets and unrealized gains (losses) on supply contract
derivatives.
|
(g)
|
Net income
attributable to noncontrolling interests of Chesapeake Granite Wash
Trust and, prior to its repurchase in the 2015 third quarter, CHK
Cleveland Tonkawa, L.L.C.
|
(h)
|
Includes capital
expenditures for drilling and completion, leasehold, geological and
geophysical costs and other property and plant and
equipment.
|
Oil and Natural Gas Hedging Activities
Chesapeake enters into oil and
natural gas 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 derivative positions and accounting
for oil and natural gas derivatives.
As of October 31, 2015, the
company had downside protection, through open swaps, on
approximately 38% of its projected 2015 fourth quarter oil
production at an average price of $86.89 per bbl. In addition, the company had
downside price protection under three-way collar arrangements on
approximately 11% of its projected 2015 fourth quarter oil
production based on an average bought put NYMEX price of
$90 per bbl and exposure below an
average sold put NYMEX price of $80
per bbl. The company had downside price protection, through
open swaps, on approximately 20% of the company's projected 2015
fourth quarter natural gas production at an average price of
$3.94 per mcf. In addition, the
company had downside price protection under three-way collar
arrangements on approximately 14% of its projected 2015 fourth
quarter natural gas production based on an average bought put NYMEX
price of $4.17 per mcf and exposure
below an average sold put NYMEX price of $3.38 per mcf. On three-way collars, if the
actual price at settlement is below the sold put, the company's
gain will be the difference between the bought put and the sold
put.
The company's crude oil hedging positions as of October 31, 2015 were as follows:
Open Crude Oil
Swaps; Gains from Closed
|
Crude Oil Trades
and Call Option Premiums
|
|
|
Open Swaps
(mbbls)
|
|
Avg. NYMEX
Price of
Open Swaps
|
|
Total Gains from
Closed Trades
and Premiums
for
Call
Options
($ in
millions)
|
Q4 2015
|
3,634
|
|
$
|
86.89
|
|
|
$
|
63
|
2016 (a)
|
12,078
|
|
52.13
|
|
|
38
|
Total 2017 –
2022
|
—
|
|
$
|
—
|
|
|
$
|
78
|
|
|
(a)
|
Certain hedging
arrangements include a sold option to extend at an average price of
$53.67 per bbl covering 2.9 mmbbls in 2016.
|
Crude Oil
Three-Way Collars
|
|
|
|
|
|
|
Open Collars
(mbbls)
|
Avg. NYMEX Sold Put
Price
|
Avg. NYMEX Bought Put
Price
|
Avg. NYMEX Sold Call
Price
|
Q4 2015
|
1,104
|
$
|
80.00
|
|
$
|
90.00
|
|
$
|
98.94
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Net
Written Call Options
|
|
|
|
|
Call
Options
(mbbls)
|
Avg. NYMEX
Strike
Price
|
Q4 2015
|
1,868
|
$
|
85.31
|
2016
|
10,951
|
96.23
|
2017
|
5,293
|
$
|
83.50
|
Crude Oil Basis
Protection Swaps
|
|
|
|
|
Volume
(mbbls)
|
Avg. NYMEX
plus
|
Q4 2015
|
2,361
|
$
|
3.14
|
The company's natural gas hedging positions as of October 31, 2015 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
Losses
from Closed
Trades
and Premiums
for
Call
Options
($ in
millions)
|
Q4 2015
|
52
|
|
$
|
3.94
|
|
$
|
(31)
|
2016
|
283
|
|
3.18
|
|
(109)
|
Total 2017 –
2022
|
—
|
|
$
|
—
|
|
$
|
(78)
|
Natural Gas
Three-Way Collars
|
|
|
Open
Collars
(bcf)
|
Avg. NYMEX
Sold
Put Price
|
Avg. NYMEX
Bought
Put Price
|
Avg. NYMEX
Sold Call
Price
|
Q4 2015
|
36
|
$
|
3.38
|
$
|
4.17
|
$
|
4.37
|
|
Natural Gas Net
Written Call Options
|
|
|
|
|
Call
Options
(bcf)
|
Avg. NYMEX
Strike
Price
|
2016
|
79
|
$
|
8.48
|
Total 2017 –
2020
|
114
|
$
|
10.92
|
Natural Gas Basis
Protection Swaps
|
|
|
|
|
Volume
(bcf)
|
Avg. NYMEX
plus/(minus)
|
Q4 2015
|
18
|
$
|
0.37
|
2016
|
33
|
0.17
|
Total 2017 -
2022
|
24
|
$
|
(0.48)
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2015-third-quarter-financial-and-operational-results-300171746.html
SOURCE Chesapeake Energy Corporation