OKLAHOMA CITY, May 2, 2018 /PRNewswire/ -- Chesapeake Energy
Corporation (NYSE:CHK) today reported financial and operational
results for the 2018 first quarter. Highlights include:
- 2018 first quarter net income available to common
stockholders of $268 million, or
$0.29 per diluted share; 2018 first
quarter adjusted net income available to common stockholders of
$361 million, or $0.34 per diluted share
- 2018 first quarter net cash provided by operating
activities increased $557 million
compared to 2017 first quarter
- Reduced $581 million
principal amount of long-term debt in 2018 first
quarter
- Average 2018 first quarter production of approximately
554,000 barrels of oil equivalent (boe) per day, up 11 percent
compared to 2017 first quarter, adjusted for asset
sales
- Average 2018 first quarter oil production of
approximately 92,000 barrels of oil per day, up 16 percent compared
to 2017 first quarter, adjusted for asset sales
Doug Lawler, Chesapeake's Chief Executive Officer,
commented, "The strength of our operations and improved cost
structure, coupled with higher realized prices, resulted in our
best quarterly financial performance in over three years. For the
second consecutive quarter, we recorded significant growth in our
earnings and cash flow. Notably, our margin improvement,
while aided by increases in commodity indices, was primarily driven
by strong oil production and a lower cost structure, highlighting
the differential profit generated beyond price impacts, and
the sustainability of our improving financial performance. The net
cash flow provided by operating and investing activities, including
net proceeds from asset sales, was $609
million for the quarter and was the highest in more than
three years, allowing us to reduce our long-term debt by
$581 million. Our results provide
further evidence that we are achieving our long term goals of
growing cash flow, expanding margins, reducing long term debt and
generating higher returns to shareholders."
2018 First Quarter Results
For the 2018 first quarter, Chesapeake reported net income of $294 million and net income available to common
stockholders of $268 million, or
$0.29 per diluted share. The
company's EBITDA for the 2018 first quarter was $703 million. Adjusting for items that are
typically excluded by securities analysts, the 2018 first quarter
adjusted net income attributable to Chesapeake was $361
million, or $0.34 per diluted
share, while the company's adjusted EBITDA was $733 million. Reconciliations of financial
measures calculated in accordance with GAAP to non-GAAP measures
are provided on pages 11 - 13 of this release.
Production expenses during the 2018 first quarter were
$2.94 per boe, while general and
administrative expenses (including stock-based compensation) during
the 2018 first quarter were $1.44 per
boe. The increase in production expenses was primarily the result
of increased saltwater disposal costs and workover activity. With
regard to general and administrative expenses, lower compensation
costs were more than offset by lower overhead allocations,
primarily as a result of certain 2017 divestitures. Chesapeake's combined production and general
and administrative expenses per boe increased by 5 percent year
over year. However, the company's gathering, processing, and
transportation expenses decreased by 4 percent year over year to
$7.15 per boe during the 2018 first
quarter, resulting in lower overall expenses per unit of production
on a combined basis.
Capital Spending Overview
Chesapeake's total capital
expenditures (including accruals) were approximately $611 million during the 2018 first quarter,
including capitalized interest of $43
million, compared to approximately $576 million in the 2017 first quarter. A summary
is provided in the table below.
|
|
Three Months
Ended March
31,
|
|
|
2018
|
|
2017
|
Operated activity
comparison
|
|
|
|
|
Average rig
count
|
|
15
|
|
16
|
Gross wells
spud
|
|
77
|
|
87
|
Gross wells
completed
|
|
76
|
|
99
|
Gross wells
connected
|
|
57
|
|
76
|
|
|
|
|
|
Type of cost ($ in
millions)
|
|
|
|
|
Drilling and
completion capital expenditures
|
|
$
|
539
|
|
|
$
|
506
|
|
Exploration costs,
leasehold and additions to other PP&E
|
|
29
|
|
|
19
|
|
Subtotal capital
expenditures
|
|
$
|
568
|
|
|
$
|
525
|
|
Capitalized
interest
|
|
43
|
|
|
51
|
|
Total capital
expenditures
|
|
$
|
611
|
|
|
$
|
576
|
|
Balance Sheet and Liquidity
As of March 31, 2018, Chesapeake's principal debt balance was
approximately $9.400 billion,
compared to $9.981 billion as of
December 31, 2017. Also, as of
March 31, 2018, the company had
$200 million of outstanding
borrowings and had used $157 million
for various letters of credit under the senior secured revolving
credit facility resulting in approximately $3.4 billion of available liquidity under the
facility.
During the 2018 first quarter, the company closed certain
property sales for net proceeds of approximately $387 million. In addition, in February 2018 Chesapeake sold approximately 4.3
million shares of FTS International (NYSE: FTSI) for approximately
$74 million in net proceeds and
continues to hold approximately 22.0 million shares in the publicly
traded company. FTSI is a provider of hydraulic fracturing
services in North America.
Chesapeake used the $461 million in aggregate proceeds described
above to reduce its outstanding borrowings under its revolving
credit facility. Subsequent to the 2018 first quarter, in April the
company closed an additional asset sale for properties in the
Mid-Continent for approximately $60
million in net proceeds which reduced Chesapeake's outstanding borrowings under its
revolving credit facility.
Operations Update
Chesapeake's average daily
production for the 2018 first quarter was approximately 554,000 boe
compared to approximately 528,000 boe in the 2017 first quarter.
The following tables show average daily production and average
daily sales prices received by the company's operating divisions
for the 2018 and 2017 first quarters, respectively.
|
|
Three Months Ended
March 31, 2018
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
873
|
|
|
3.74
|
|
|
—
|
|
|
—
|
|
|
146
|
|
|
26
|
|
|
22.46
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
833
|
|
|
2.80
|
|
|
—
|
|
|
—
|
|
|
139
|
|
|
25
|
|
|
16.86
|
|
Eagle Ford
|
|
61
|
|
|
66.16
|
|
|
141
|
|
|
3.30
|
|
|
18
|
|
|
24.72
|
|
|
102
|
|
|
19
|
|
|
48.22
|
|
Utica
|
|
11
|
|
|
59.82
|
|
|
440
|
|
|
2.94
|
|
|
23
|
|
|
25.03
|
|
|
107
|
|
|
19
|
|
|
23.39
|
|
Mid-Continent
|
|
9
|
|
|
62.04
|
|
|
87
|
|
|
2.70
|
|
|
5
|
|
|
26.15
|
|
|
28
|
|
|
5
|
|
|
32.46
|
|
Powder River
Basin
|
|
7
|
|
|
62.86
|
|
|
47
|
|
|
2.82
|
|
|
3
|
|
|
28.77
|
|
|
18
|
|
|
3
|
|
|
37.68
|
|
Retained
assets(a)
|
|
88
|
|
|
64.66
|
|
|
2,421
|
|
|
3.19
|
|
|
49
|
|
|
25.24
|
|
|
540
|
|
|
97
|
|
|
27.10
|
|
Divested
assets
|
|
4
|
|
|
63.60
|
|
|
45
|
|
|
2.81
|
|
|
2
|
|
|
30.07
|
|
|
14
|
|
|
3
|
|
|
33.53
|
|
Total
|
|
92
|
|
|
64.61
|
|
|
2,466
|
|
|
3.18
|
|
|
51
|
|
|
25.45
|
|
|
554
|
|
|
100
|
%
|
|
27.27
|
|
|
|
|
Three Months Ended
March 31, 2017
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
837
|
|
|
3.01
|
|
|
—
|
|
|
—
|
|
|
139
|
|
|
27
|
|
|
18.04
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
682
|
|
|
2.98
|
|
|
—
|
|
|
—
|
|
|
114
|
|
|
22
|
|
|
17.86
|
|
Eagle Ford
|
|
56
|
|
|
50.90
|
|
|
135
|
|
|
3.40
|
|
|
17
|
|
|
21.38
|
|
|
96
|
|
|
18
|
|
|
38.52
|
|
Utica
|
|
8
|
|
|
45.42
|
|
|
380
|
|
|
3.50
|
|
|
25
|
|
|
25.65
|
|
|
96
|
|
|
18
|
|
|
24.16
|
|
Mid-Continent
|
|
7
|
|
|
49.64
|
|
|
92
|
|
|
3.04
|
|
|
6
|
|
|
22.45
|
|
|
28
|
|
|
5
|
|
|
26.73
|
|
Powder River
Basin
|
|
5
|
|
|
49.70
|
|
|
29
|
|
|
3.33
|
|
|
2
|
|
|
25.58
|
|
|
12
|
|
|
2
|
|
|
32.67
|
|
Retained
assets(a)
|
|
76
|
|
|
50.16
|
|
|
2,155
|
|
|
3.11
|
|
|
50
|
|
|
23.81
|
|
|
485
|
|
|
92
|
|
|
24.13
|
|
Divested
assets
|
|
8
|
|
|
50.96
|
|
|
187
|
|
|
2.88
|
|
|
4
|
|
|
23.43
|
|
|
43
|
|
|
8
|
|
|
24.06
|
|
Total
|
|
84
|
|
|
50.24
|
|
|
2,342
|
|
|
3.10
|
|
|
54
|
|
|
23.78
|
|
|
528
|
|
|
100
|
%
|
|
24.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes assets
retained as of March 31, 2018.
|
In the Powder River Basin (PRB) in Wyoming, Chesapeake is currently utilizing four rigs,
all of which are drilling in the Turner formation. Chesapeake placed six wells on production
during the 2018 first quarter in the PRB and expects to place 12
wells on production during the 2018 second quarter and up to 35
wells for the full-year 2018.
As part of a reduced Turner spacing test, six of the
company's 12 second quarter wells were placed on
production in April 2018 and spaced at approximately
1,980 to 2,300 feet apart. While currently on conservative choke
settings between 20 and 22/64ths, the six wells have ranged from 6
to 19 days on production with current flowing tubing pressures
ranging from 2,750 to 3,050 pounds. The company is encouraged by
initial results from these tighter-spaced wells, as the bounded
middle well spaced at approximately 1,980 feet has already reached
a production rate of approximately ~2,000 boe per day (46% oil)
after 18 days on production. The company expects significantly
higher rates as these wells clean up over the next 30 days.
In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing two drilling
rigs and placed eight wells on production during the 2018 first
quarter and expects to place nine wells on production during the
2018 second quarter and up to 35 wells for the full-year 2018.
Chesapeake has drilled its first
horizontal well targeting the Chester formation in Woods County in April
2018 and expects to place this well on production later this
quarter. While one rig will continue to drill appraisal
opportunities on the company's approximately 800,000 net acre
position during 2018, the second rig will continue developing the
Oswego oil play.
In the Eagle Ford Shale, Chesapeake is currently utilizing five
drilling rigs and placed 23 wells on production during the 2018
first quarter and expects to place approximately 50 wells on
production during the 2018 second quarter and up to 150 wells for
the full-year 2018.
In the Utica Shale in Ohio,
Chesapeake is currently utilizing
two drilling rigs and placed ten wells on production during the
2018 first quarter. The company has recently changed its completion
methodologies resulting in 30-day average daily production rates
that have increased by approximately 65 percent for its first six
wells in 2018 under this new program. Chesapeake expects to place seven wells on
production during the 2018 second quarter and up to 35 wells for
the full-year 2018.
In the Marcellus Shale, Chesapeake is currently utilizing one drilling
rig and placed six wells on production during the 2018 first
quarter and expects to place 17 wells on production during the 2018
second quarter and up to 50 wells for the full-year 2018.
In the Haynesville Shale in Louisiana, Chesapeake is currently utilizing three
drilling rigs and placed four wells on production during the 2018
first quarter and expects to place eight wells on production during
the 2018 second quarter and up to 25 wells for the full-year
2018.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and operational
results during the 2018 first quarter as compared to results in
prior periods.
|
|
Three Months Ended
March 31,
|
|
|
2018
|
|
2017
|
Barrels of oil
equivalent production (in mboe)
|
|
49,879
|
|
|
47,516
|
|
Barrels of oil
equivalent production (mboe/d)
|
|
554
|
|
|
528
|
|
Oil production (in
mbbl/d)
|
|
92
|
|
|
84
|
|
Average realized oil
price ($/bbl)(a)
|
|
56.89
|
|
|
51.72
|
|
Natural gas
production (in mmcf/d)
|
|
2,466
|
|
|
2,342
|
|
Average realized
natural gas price ($/mcf)(a)
|
|
3.49
|
|
|
3.02
|
|
NGL production (in
mbbl/d)
|
|
51
|
|
|
54
|
|
Average realized NGL
price ($/bbl)(a)
|
|
25.36
|
|
|
24.04
|
|
Production expenses
($/boe)
|
|
2.94
|
|
|
2.84
|
|
Gathering, processing
and transportation expenses ($/boe)
|
|
7.15
|
|
|
7.47
|
|
Oil -
($/bbl)
|
|
4.18
|
|
|
3.85
|
|
Natural Gas -
($/mcf)
|
|
1.27
|
|
|
1.35
|
|
NGL -
($/bbl)
|
|
8.83
|
|
|
8.47
|
|
Production taxes
($/boe)
|
|
0.62
|
|
|
0.47
|
|
General and
administrative expenses ($/boe)(b)
|
|
1.30
|
|
|
1.18
|
|
General and
administrative expenses (stock-based compensation) (non-cash)
($/boe)
|
|
0.14
|
|
|
0.17
|
|
DD&A of oil and
natural gas properties ($/boe)
|
|
5.38
|
|
|
4.15
|
|
DD&A of other
assets ($/boe)
|
|
0.36
|
|
|
0.44
|
|
Interest expense
($/boe)(a)
|
|
2.45
|
|
|
1.97
|
|
Marketing net margin
($ in millions)
|
|
(22)
|
|
|
(44)
|
|
Net cash provided by
operating activities ($ in millions)
|
|
656
|
|
|
99
|
|
Net cash provided by
operating activities ($/boe)
|
|
13.15
|
|
|
2.06
|
|
Operating cash flow
($ in millions)(c)
|
|
552
|
|
|
(14)
|
|
Operating cash flow
($/boe)
|
|
11.07
|
|
|
(0.29)
|
|
Net income ($ in
millions)
|
|
294
|
|
|
141
|
|
Net income available
to common stockholders ($ in millions)
|
|
268
|
|
|
75
|
|
Net income per share
available to common stockholders – diluted ($)
|
|
0.29
|
|
|
0.08
|
|
Adjusted EBITDA ($ in
millions)(d)
|
|
733
|
|
|
525
|
|
Adjusted EBITDA
($/boe)
|
|
14.70
|
|
|
11.05
|
|
Adjusted net income
attributable to Chesapeake ($ in millions)(e)
|
|
361
|
|
|
212
|
|
Adjusted net income
attributable to Chesapeake per
share - diluted ($ in millions)(f)
|
|
0.34
|
|
|
0.23
|
|
|
|
|
|
|
|
|
(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, which are recorded in
general and administrative expenses in Chesapeake's Condensed
Consolidated Statement of Operations.
|
|
|
(c)
|
Defined as cash flow
provided by operating activities before changes in components of
working capital and other assets and liabilities. This is a
non-GAAP measure. See reconciliation to cash provided by (used in)
operating activities on page 12.
|
|
|
(d)
|
Defined as net income
(loss) before interest expense, income taxes and depreciation,
depletion and amortization expense, as adjusted to remove the
effects of certain items detailed on page 13. This is a non-GAAP
measure. See reconciliation of net income (loss) to EBITDA on page
12 and reconciliation of EBITDA to adjusted EBITDA on page
13.
|
|
|
(e)
|
Defined as net income
(loss) attributable to Chesapeake, as adjusted to remove the
effects of certain items detailed on page 11. This is a
non-GAAP measure. See reconciliation of net income to adjusted net
income (loss) available to Chesapeake on page 11.
|
|
|
(f)
|
Our presentation of
diluted adjusted net income (loss) attributable to Chesapeake per
share excludes 60 million and 208 million shares for the three
months ended March 31, 2018 and 2017, respectively, considered
antidilutive when calculating diluted earnings per
share.
|
2018 First Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled on
Wednesday, May 2, 2018 at
9:00 am EDT. The telephone number to
access the conference call is 323-794-2093 or toll-free
866-548-4713. The passcode for the call is 2838919. The number to
access the conference call replay is 719-457-0820 or toll-free
888-203-1112 and the passcode for the replay is 2838919. The
conference call will be webcast and can be found 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.
Headquartered in Oklahoma
City, Chesapeake Energy Corporation's (NYSE: CHK) operations
are focused on discovering and developing its large and
geographically diverse resource base of unconventional oil and
natural gas assets onshore in the United
States.
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, management's outlook guidance
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, anticipated timing of wells to be placed
into production, general and administrative expenses, capital
expenditures, the timing of anticipated asset sales and proceeds to
be received therefrom, the expected use of proceeds of anticipated
asset sales, projected cash flow and liquidity, our
ability to enhance our cash flow and financial flexibility, plans
and objectives for future operations, 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; the
limitations our level of indebtedness may have on our financial
flexibility; our inability to access the capital markets on
favorable terms; the availability of cash flows from operations and
other funds to finance reserve replacement costs or satisfy our
debt obligations; downgrade in our credit rating requiring us to
post more collateral under certain commercial arrangements;
write-downs of our oil and natural gas asset carrying values due to
low commodity prices; 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; charges incurred
in response to market conditions and in connection with our ongoing
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; impacts of
potential legislative and regulatory actions addressing climate
change; federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge
against commodity price fluctuations; 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; terrorist activities and
cyber-attacks adversely impacting our operations; an interruption
in operations at our headquarters due to a catastrophic event;
certain anti-takeover provisions that affect shareholder rights;
and our inability to increase or maintain our liquidity through
debt repurchases, capital exchanges, asset sales, joint ventures,
farmouts or other means.
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. In addition, this news release contains
time-sensitive information that reflects management's best judgment
only as of the date of this news release.
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
(405)
935-8870
ir@chk.com
|
Gordon
Pennoyer
(405)
935-8878
media@chk.com
|
CHESAPEAKE ENERGY
CORPORATION CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share
data) (unaudited)
|
|
|
Three Months
Ended March 31,
|
|
|
2018
|
|
2017
|
REVENUES:
|
|
|
|
|
Oil, natural gas and
NGL
|
|
$
|
1,243
|
|
|
$
|
1,469
|
|
Marketing
|
|
1,246
|
|
|
1,284
|
|
Total
Revenues
|
|
2,489
|
|
|
2,753
|
|
OPERATING
EXPENSES:
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
147
|
|
|
135
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
|
356
|
|
|
355
|
|
Production
taxes
|
|
31
|
|
|
22
|
|
Marketing
|
|
1,268
|
|
|
1,328
|
|
General and
administrative
|
|
72
|
|
|
65
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
(2)
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
268
|
|
|
197
|
|
Depreciation and
amortization of other assets
|
|
18
|
|
|
21
|
|
Other operating
expense
|
|
—
|
|
|
391
|
|
Net losses on sales
of fixed assets
|
|
8
|
|
|
—
|
|
Total Operating
Expenses
|
|
2,211
|
|
|
2,512
|
|
INCOME FROM
OPERATIONS
|
|
278
|
|
|
241
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
Interest
expense
|
|
(123)
|
|
|
(95)
|
|
Gains on
investments
|
|
139
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
—
|
|
|
(7)
|
|
Other
income
|
|
—
|
|
|
3
|
|
Total Other Income
(Expense)
|
|
16
|
|
|
(99)
|
|
INCOME BEFORE
INCOME TAXES
|
|
294
|
|
|
142
|
|
Income tax
expense
|
|
—
|
|
|
1
|
|
NET
INCOME
|
|
294
|
|
|
141
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
(1)
|
|
NET INCOME
ATTRIBUTABLE TO CHESAPEAKE
|
|
293
|
|
|
140
|
|
Preferred stock
dividends
|
|
(23)
|
|
|
(23)
|
|
Loss on exchange of
preferred stock
|
|
—
|
|
|
(41)
|
|
Earnings allocated to
participating securities
|
|
(2)
|
|
|
(1)
|
|
NET INCOME
AVAILABLE TO COMMON STOCKHOLDERS
|
|
$
|
268
|
|
|
$
|
75
|
|
EARNINGS PER
COMMON SHARE:
|
|
|
|
|
Basic
|
|
$
|
0.30
|
|
|
$
|
0.08
|
|
Diluted
|
|
$
|
0.29
|
|
|
$
|
0.08
|
|
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
Basic
|
|
907
|
|
|
906
|
|
Diluted
|
|
1,053
|
|
|
907
|
|
CHESAPEAKE ENERGY
CORPORATION CONDENSED
CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited)
|
|
|
March 31,
2018
|
|
December 31,
2017
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
4
|
|
|
$
|
5
|
|
Other current
assets
|
|
1,220
|
|
|
1,520
|
|
Total Current
Assets
|
|
1,224
|
|
|
1,525
|
|
|
|
|
|
|
Property and
equipment, net
|
|
10,592
|
|
|
10,680
|
|
Other long-term
assets
|
|
270
|
|
|
220
|
|
Total
Assets
|
|
$
|
12,086
|
|
|
$
|
12,425
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
2,354
|
|
|
$
|
2,356
|
|
Long-term debt,
net
|
|
9,325
|
|
|
9,921
|
|
Other long-term
liabilities
|
|
504
|
|
|
520
|
|
Total
Liabilities
|
|
12,183
|
|
|
12,797
|
|
|
|
|
|
|
Preferred
stock
|
|
1,671
|
|
|
1,671
|
|
Noncontrolling
interests
|
|
123
|
|
|
124
|
|
Common stock and
other stockholders' equity (deficit)
|
|
(1,891)
|
|
|
(2,167)
|
|
Total Equity
(Deficit)
|
|
(97)
|
|
|
(372)
|
|
|
|
|
|
|
Total Liabilities
and Equity
|
|
$
|
12,086
|
|
|
$
|
12,425
|
|
|
|
|
|
|
Common shares
outstanding (in millions)
|
|
912
|
|
|
909
|
|
Principal amount of
debt outstanding
|
|
$
|
9,400
|
|
|
$
|
9,981
|
|
CHESAPEAKE ENERGY
CORPORATION SUPPLEMENTAL
DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST
EXPENSE (unaudited)
|
|
|
Three Months
Ended
March 31,
|
|
|
2018
|
|
2017
|
Net
Production:
|
|
|
|
|
Oil
(mmbbl)
|
|
8
|
|
|
8
|
|
Natural gas
(bcf)
|
|
222
|
|
|
211
|
|
NGL
(mmbbl)
|
|
5
|
|
|
5
|
|
Oil equivalent
(mmboe)
|
|
50
|
|
|
48
|
|
Average daily
production (mboe)
|
|
554
|
|
|
528
|
|
Oil, natural gas
and NGL Sales ($ in millions):
|
|
|
|
|
Oil sales
|
|
$
|
537
|
|
|
$
|
378
|
|
Natural gas
sales
|
|
706
|
|
|
653
|
|
NGL sales
|
|
117
|
|
|
116
|
|
Total oil, natural
gas and NGL sales
|
|
$
|
1,360
|
|
|
$
|
1,147
|
|
|
|
|
|
|
Financial
Derivatives:
|
|
|
|
|
Oil derivatives –
realized gains (losses)(a)
|
|
$
|
(64)
|
|
|
11
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
|
67
|
|
|
(16)
|
|
NGL derivatives –
realized gains (losses)(a)
|
|
(1)
|
|
|
1
|
|
Total realized gains
(losses) on financial derivatives
|
|
$
|
2
|
|
|
$
|
(4)
|
|
|
|
|
|
|
Oil derivatives –
unrealized gains (losses)(a)
|
|
(22)
|
|
|
94
|
|
Natural gas
derivatives – unrealized gains (losses)(a)
|
|
(99)
|
|
|
231
|
|
NGL derivatives –
unrealized gains(a)
|
|
2
|
|
|
1
|
|
Total unrealized
gains (losses) on financial derivatives
|
|
$
|
(119)
|
|
|
$
|
326
|
|
|
|
|
|
|
Total financial
derivatives
|
|
$
|
(117)
|
|
|
$
|
322
|
|
|
|
|
|
|
Total oil, natural
gas and NGL sales
|
|
$
|
1,243
|
|
|
$
|
1,469
|
|
Average Sales
Price (excluding gains (losses) on derivatives):
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
64.61
|
|
|
$
|
50.24
|
|
Natural gas ($ per
mcf)
|
|
$
|
3.18
|
|
|
$
|
3.10
|
|
NGL ($ per
bbl)
|
|
$
|
25.45
|
|
|
$
|
23.78
|
|
Oil equivalent ($ per
boe)
|
|
$
|
27.27
|
|
|
$
|
24.13
|
|
Average Sales
Price (excluding unrealized gains (losses) on
derivatives):
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
56.89
|
|
|
$
|
51.72
|
|
Natural gas ($ per
mcf)
|
|
$
|
3.49
|
|
|
$
|
3.02
|
|
NGL ($ per
bbl)
|
|
$
|
25.36
|
|
|
$
|
24.04
|
|
Oil equivalent ($ per
boe)
|
|
$
|
27.31
|
|
|
$
|
24.06
|
|
Interest Expense
($ in millions):
|
|
|
|
|
Interest
expense(b)
|
|
$
|
123
|
|
|
$
|
94
|
|
Interest rate
derivatives – realized gains(c)
|
|
(1)
|
|
|
(1)
|
|
Interest rate
derivatives – unrealized losses(c)
|
|
1
|
|
|
2
|
|
Total Interest
Expense
|
|
$
|
123
|
|
|
$
|
95
|
|
|
|
(a)
|
Realized gains
(losses) include the following items: (i) settlements and accruals
for settlements of undesignated 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 (losses) related to de-designated cash flow hedges
originally designated to settle against current period production
revenues. Unrealized gains (losses) include the change in fair
value of open derivatives scheduled to settle against future period
production revenues (including current period settlements for
option premiums and early terminated derivatives) offset by amounts
reclassified as realized gains (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 interest rate derivative settlements related to
current period interest and the effect of (gains) losses on
early-terminated trades. Settlements of early-terminated trades are
reflected in realized (gains) losses over the original life of the
hedged item. 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,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
Beginning cash and
cash equivalents
|
|
$
|
5
|
|
|
$
|
882
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
656
|
|
|
99
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(442)
|
|
|
(433)
|
|
Acquisitions of
proved and unproved properties(b)
|
|
(63)
|
|
|
(95)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
319
|
|
|
892
|
|
Additions to other
property and equipment
|
|
(3)
|
|
|
(3)
|
|
Proceeds from sales
of other property and equipment
|
|
68
|
|
|
19
|
|
Proceeds from sales
of investments
|
|
74
|
|
|
—
|
|
Net cash provided
by (used in) investing activities
|
|
(47)
|
|
|
380
|
|
|
|
|
|
|
Net cash used in
financing activities
|
|
(610)
|
|
|
(1,112)
|
|
Change in cash and
cash equivalents
|
|
(1)
|
|
|
(633)
|
|
Ending cash and
cash equivalents
|
|
$
|
4
|
|
|
$
|
249
|
|
|
|
(a)
|
Includes capitalized
interest of $2 million and $2 million for the three months ended
March 31, 2018 and 2017, respectively.
|
|
|
(b)
|
Includes capitalized
interest of $41 million and $49 million for the three months ended
March 31, 2018 and 2017, respectively.
|
CHESAPEAKE ENERGY
CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO
COMMON STOCKHOLDERS ($
in millions except per share data) (unaudited)
|
|
|
Three Months Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
$
|
|
$/Share(b)(c)
|
|
$
|
|
$/Share(b)(c)
|
Net income
available to common stockholders (GAAP)
|
|
$
|
268
|
|
|
$
|
0.30
|
|
|
$
|
75
|
|
|
$
|
0.08
|
|
Effect of dilutive
securities
|
|
36
|
|
|
|
|
—
|
|
|
|
Diluted earnings per
common stockholder (GAAP)
|
|
$
|
304
|
|
|
$
|
0.29
|
|
|
$
|
75
|
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
119
|
|
|
0.11
|
|
|
(326)
|
|
|
(0.36)
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
0.04
|
|
|
—
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
—
|
|
|
(2)
|
|
|
—
|
|
Other operating
expense
|
|
—
|
|
|
—
|
|
|
391
|
|
|
0.43
|
|
Net losses on sales
of fixed assets
|
|
8
|
|
|
0.01
|
|
|
—
|
|
|
—
|
|
Gains on
investments
|
|
(139)
|
|
|
(0.13)
|
|
|
—
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
—
|
|
|
—
|
|
|
7
|
|
|
0.01
|
|
Loss on exchange of
preferred stock
|
|
—
|
|
|
—
|
|
|
41
|
|
|
0.05
|
|
Other
|
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Adjusted net
income available to common stockholders(b)
(Non-GAAP)
|
|
336
|
|
|
0.32
|
|
|
188
|
|
|
0.21
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
0.02
|
|
|
23
|
|
|
0.02
|
|
Earnings allocated to
participating securities
|
|
2
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Total adjusted net
income attributable to Chesapeake(b) (c)
(Non-GAAP)
|
|
$
|
361
|
|
|
$
|
0.34
|
|
|
$
|
212
|
|
|
$
|
0.23
|
|
|
|
(a)
|
Our effective tax
rate in the three months ended March 31, 2018 was 0%. Due to our
valuation allowance position, no income tax effect from the
adjustments has been included in determining adjusted net income
for the three months ended March 31, 2017.
|
|
|
(b)
|
Adjusted net income
(loss) available to common stockholders and total adjusted net
income (loss) attributable to Chesapeake, both in the aggregate and
per dilutive share, are not measures of financial performance under
GAAP, and should not be considered as an alternative to, or more
meaningful than, net income (loss) available to common stockholders
or earnings (loss) per share. Adjusted net income (loss) available
to common stockholders and adjusted earnings (loss) per share
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 (loss) 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
(loss) 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.
|
|
|
|
Because adjusted net
income (loss) available to common stockholders and total adjusted
net income (loss) attributable to Chesapeake exclude some, but not
all, items that affect net income (loss) available to common
stockholders and total adjusted net income (loss) attributable to
Chesapeake may vary among companies, our calculation of adjusted
net income (loss) available to common stockholders and total
adjusted net income (loss) attributable to Chesapeake may not be
comparable to similarly titled financial measures of other
companies.
|
|
|
(c)
|
Our presentation of
diluted net income (loss) available to common stockholders and
diluted adjusted net income (loss) per share excludes 60 million
and 208 million shares considered antidilutive for the three months
ended March 31, 2018 and 2017, respectively. The number of shares
used for the non-GAAP calculation was determined in a manner
consistent with GAAP.
|
CHESAPEAKE ENERGY
CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND
EBITDA ($ in
millions) (unaudited)
|
|
|
Three Months
Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
|
$
|
656
|
|
|
$
|
99
|
|
Changes in components
of working capital and other assets and liabilities
|
|
(104)
|
|
|
(113)
|
|
OPERATING CASH
FLOW (Non-GAAP)(a)
|
|
$
|
552
|
|
|
$
|
(14)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
NET INCOME
(GAAP)
|
|
$
|
294
|
|
|
$
|
141
|
|
Interest
expense
|
|
123
|
|
|
95
|
|
Income tax
expense
|
|
—
|
|
|
1
|
|
Depreciation and
amortization of other assets
|
|
18
|
|
|
21
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
268
|
|
|
197
|
|
EBITDA
(Non-GAAP)(b)
|
|
$
|
703
|
|
|
$
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
|
$
|
656
|
|
|
$
|
99
|
|
Changes in assets and
liabilities
|
|
(104)
|
|
|
(113)
|
|
Interest expense, net
of unrealized gains (losses) on derivatives
|
|
123
|
|
|
93
|
|
Gains (losses) on
oil, natural gas and NGL derivatives, net
|
|
(117)
|
|
|
322
|
|
Cash (receipts)
payments on derivative settlements, net
|
|
(13)
|
|
|
34
|
|
Stock-based
compensation
|
|
(9)
|
|
|
(11)
|
|
Net losses on sales
of fixed assets
|
|
(8)
|
|
|
—
|
|
Gains on
investments
|
|
139
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
—
|
|
|
(6)
|
|
Other
items
|
|
36
|
|
|
37
|
|
EBITDA
(Non-GAAP)(b)
|
|
$
|
703
|
|
|
$
|
455
|
|
|
|
(a)
|
Operating cash flow
represents net cash provided by operating activities before changes
in components of working capital and other. Operating cash flow is
presented because management believes it is a useful adjunct to net
cash provided by operating activities under GAAP and provides
useful information to investors for analysis of the Company's
ability to generate cash to fund exploration and development, and
to service debt. 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 activities as an indicator of cash flows, or as a measure
of liquidity. Because operating cash flow excludes some, but not
all, items that affect net cash provided by operating activities
and may vary among companies, our calculation of operating cash
flow may not be comparable to similarly titled measures of other
companies. The increase in operating cash flow for the three months
ended March 31, 2018 is mainly due to an increase in prices and
volumes.
|
|
|
(b)
|
EBITDA represents net
income before interest expense, income tax expense, 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 (or liquidity) under GAAP. Accordingly, it should not
be considered as a substitute for net income, income from
operations or cash flows from operating activities prepared in
accordance with GAAP.
|
CHESAPEAKE ENERGY
CORPORATION RECONCILIATION OF ADJUSTED
EBITDA ($ in
millions) (unaudited)
|
|
|
Three Months
Ended
March 31,
|
|
|
2018
|
|
2017
|
|
|
|
|
|
EBITDA
(Non-GAAP)
|
|
$
|
703
|
|
|
$
|
455
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized losses
(gains) on oil, natural gas and NGL derivatives
|
|
119
|
|
|
(326)
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
(2)
|
|
Other operating
expense
|
|
—
|
|
|
391
|
|
Net losses on sales
of fixed assets
|
|
8
|
|
|
—
|
|
Gains on
investments
|
|
(139)
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
—
|
|
|
7
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
(1)
|
|
Other
|
|
—
|
|
|
1
|
|
|
|
|
|
|
Adjusted EBITDA
(Non-GAAP)(a)
|
|
$
|
733
|
|
|
$
|
525
|
|
|
|
(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.
Because adjusted EBITDA excludes some, but not all, items that
affect net income (loss from continuing operations) attributable to
common stockholders, our calculations of adjusted EBITDA may not be
comparable to similarly titled measures of other companies.
CHESAPEAKE ENERGY
CORPORATION
|
MANAGEMENT'S
OUTLOOK AS OF MAY 1, 2018
|
Chesapeake
periodically provides guidance on certain factors that affect the
company's future financial performance. New information or changes
from the company's February 22, 2018 outlook are italicized
bold below.
|
|
|
Year
Ending
12/31/2018
|
|
|
Production Growth
adjusted for asset sales(a)
|
1% to 5%
|
Absolute
Production
|
|
Liquids -
mmbbls
|
51.0 -
55.0
|
Oil -
mmbbls
|
31.0 -
33.0
|
NGL -
mmbbls
|
20.0 -
22.0
|
Natural gas -
bcf
|
825 - 875
|
Total absolute
production - mmboe
|
190 - 200
|
Absolute daily rate -
mboe
|
515 - 550
|
Estimated Realized
Hedging Effects(b) (based on 4/27/18 strip
prices):
|
|
Oil -
$/bbl
|
($10.20)
|
Natural gas -
$/mcf
|
$0.13
|
NGL -
$/bbl
|
$(0.13)
|
Estimated Basis to
NYMEX Prices:
|
|
Oil -
$/bbl
|
$1.00 -
$1.20
|
Natural gas -
$/mcf
|
($0.10) -
($0.20)
|
NGL -
$/bbl
|
($5.20) -
($5.60)
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$2.60 -
$2.80
|
Gathering, processing
and transportation expenses
|
$6.95 -
$7.65
|
Oil -
$/bbl
|
$3.90 -
$4.10
|
Natural Gas -
$/mcf
|
$1.25 -
$1.40
|
NGL -
$/bbl
|
$7.85 -
$8.25
|
Production
taxes
|
$0.50 -
$0.60
|
General and
administrative(c)
|
$1.25 -
$1.35
|
Stock-based
compensation (noncash)
|
$0.10 -
$0.20
|
DD&A of natural
gas and liquids assets
|
$5.00 -
$6.00
|
Depreciation of other
assets
|
$0.35 -
$0.45
|
Interest
expense(d)
|
$2.40 -
$2.60
|
Marketing net
margin(e)
|
($60) -
($40)
|
Book Tax
Rate
|
0%
|
Adjusted EBITDA,
based on 4/27/18 strip prices ($ in
millions)(f)
|
$2,250 -
$2,450
|
Capital Expenditures
($ in millions)(g)
|
$1,800 -
$2,200
|
Capitalized Interest
($ in millions)
|
$175
|
Total Capital
Expenditures ($ in millions)
|
$1,975 -
$2,375
|
|
|
(a)
|
Based on 2017
production of 514 mboe per day, adjusted for 2017 asset sales and
2018 asset sales signed to date.
|
|
|
(b)
|
Includes expected
settlements for oil, natural gas and NGL derivatives adjusted for
option premiums. For derivatives closed early, settlements are
reflected in the period of original contract expiration.
|
|
|
(c)
|
Excludes expenses
associated with stock-based compensation, which are recorded in
general and administrative expenses in Chesapeake's Consolidated
Statement of Operations.
|
|
|
(d)
|
Excludes unrealized
gains (losses) on interest rate derivatives.
|
|
|
(e)
|
Excludes non-cash
amortization of approximately $19 million.
|
|
|
(f)
|
Adjusted EBITDA is a
non-GAAP measure used by management to evaluate the company's
operational trends and performance relative to other oil and
natural gas producing companies. Adjusted EBITDA excludes certain
items that management believes affect the comparability of
operating results. The most directly comparable GAAP measure is net
income but, it is not possible, without unreasonable efforts, to
identify the amount or significance of events or transactions that
may be included in future GAAP net income but that management does
not believe to be representative of underlying business
performance. The company further believes that providing estimates
of the amounts that would be required to reconcile forecasted
adjusted EBITDA to forecasted GAAP net income would imply a degree
of precision that may be confusing or misleading to investors.
Items excluded from net income to arrive at adjusted EBITDA include
interest expense, income taxes, and depreciation, depletion and
amortization expense as well as one-time items or items whose
timing or amount cannot be reasonably estimated.
|
|
|
(g)
|
Includes capital
expenditures for drilling and completion, leasehold, geological and
geophysical costs, rig termination payments and other property,
plant and equipment. Excludes any additional proved property
acquisitions.
|
|
|
Oil, Natural Gas and Natural Gas Liquids Hedging
Activities
Chesapeake enters into oil,
natural gas 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 derivative positions and accounting
for oil, natural gas and natural gas liquids derivatives.
As of April 27, 2018, including
April and May derivative contracts that have settled, the company
had downside price protection on a portion of its 2018 oil, natural
gas and natural gas liquids production. The company had downside
oil price protection through swaps at an average price of
$53.78 per bbl, and under three-way
collar arrangements based on an average bought put NYMEX price of
$47.00 per bbl and exposure below an
average sold put NYMEX price of $39.15 per bbl. The company had downside gas
price protection through swaps and two-way collars at an average
price of $2.96 per mcf. Chesapeake also had downside ethane, propane,
butane, isobutane and natural gasoline price protection through
swaps at an average price of $0.28,
$0.78, $0.88, $0.92 and
$1.42 per gallon (as well as a
portion of butane at 70.5 percent of WTI),
respectively. Further details summarized below.
In addition, the company had downside protection, through open
swaps on a portion of its 2019 oil production at an average price
of $57.87 per bbl. The company also
initiated downside protection on a portion of its 2019 gas
production under three-way collar arrangements based on an average
bought put NYMEX price of $2.80 per
mcf and exposure below an average sold put NYMEX price of
$2.50 per mcf.
The company's crude oil hedging positions were as follows:
Crude Oil
Swaps
Gains (Losses)
from Closed Crude Oil Trades
|
|
Swaps
(mbbls)
|
|
Avg.
NYMEX
Price
of
Swaps
|
|
Gains/Losses
from Closed
Trades
($ in
millions)
|
|
|
|
|
|
|
Q2 2018
|
5,886
|
|
$
|
52.80
|
|
|
$
|
(1)
|
|
Q3 2018
|
5,612
|
|
$
|
54.30
|
|
|
(1)
|
|
Q4 2018
|
5,612
|
|
$
|
54.30
|
|
|
(1)
|
|
Total 2018
|
17,110
|
|
$
|
53.78
|
|
|
$
|
(3)
|
|
|
|
|
|
|
|
Total 2019
|
11,661
|
|
$
|
57.87
|
|
|
$
|
(8)
|
|
Crude Oil Net
Written Call Options
|
|
Call
Options
(mbbls)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q3 2018
|
920
|
|
$
|
52.87
|
|
Q4 2018
|
920
|
|
$
|
52.87
|
|
Total 2018
|
1,840
|
|
$
|
52.87
|
|
Crude Oil
Three-Way Collars
|
|
|
Collars
(mbbls)
|
|
Avg. NYMEX
Sold Put Price
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
|
Q2 2018
|
|
455
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Q3 2018
|
|
460
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Q4 2018
|
|
460
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Total 2018
|
|
1,375
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q2 2018
|
2,639
|
|
$
|
3.21
|
|
Q3 2018
|
2,760
|
|
$
|
3.42
|
|
Q4 2018
|
2,760
|
|
$
|
3.42
|
|
Total 2018
|
8,159
|
|
$
|
3.35
|
|
The company's natural gas hedging positions were as follows:
Natural Gas
Swaps
Losses from Closed
Natural Gas Trades
|
|
Swaps
(bcf)
|
|
Avg.
NYMEX
Price
of
Swaps
|
|
Losses
from Closed
Trades
($ in
millions)
|
|
|
|
|
|
|
Q2 2018
|
118
|
|
$
|
2.92
|
|
|
$
|
(4)
|
|
Q3 2018
|
120
|
|
$
|
2.94
|
|
|
(4)
|
|
Q4 2018
|
120
|
|
$
|
3.00
|
|
|
(6)
|
|
Total 2018
|
358
|
|
$
|
2.95
|
|
|
$
|
(14)
|
|
|
|
|
|
|
|
Total 2019 -
2022
|
|
|
|
|
$
|
(49)
|
|
Natural Gas
Two-Way Collars
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q2 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Q3 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Q4 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Total 2018
|
36
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Natural Gas
Three-Way Collars
|
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Sold Put Price
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
|
Total 2019
|
|
87
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Net
Written Call Options
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q2 2018
|
16
|
|
$
|
6.27
|
|
Q3 2018
|
17
|
|
$
|
6.27
|
|
Q4 2018
|
17
|
|
$
|
6.27
|
|
Total 2018
|
50
|
|
$
|
6.27
|
|
|
|
|
|
Total 2019 –
2020
|
44
|
|
$
|
12.00
|
|
Natural Gas Basis
Protection Swaps
|
|
Volume
(bcf)
|
|
Avg. NYMEX
plus/(minus)
|
|
|
|
|
Q2 2018
|
18
|
|
$
|
(0.77)
|
|
Q3 2018
|
17
|
|
$
|
(0.77)
|
|
Q4 2018
|
6
|
|
$
|
(0.77)
|
|
Total 2018
|
41
|
|
$
|
(0.77)
|
|
|
|
|
|
Total 2019
|
4
|
|
$
|
2.24
|
|
The company's natural gas liquids hedging positions were as
follows:
Ethane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q2 2018
|
4
|
|
$
|
0.28
|
|
Total 2018
|
4
|
|
$
|
0.28
|
|
Propane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q2 2018
|
12
|
|
$
|
0.78
|
|
Q3 2018
|
15
|
|
$
|
0.79
|
|
Q4 2018
|
15
|
|
$
|
0.79
|
|
Total 2018
|
42
|
|
$
|
0.79
|
|
Butane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q2 2018
|
1
|
|
$
|
0.88
|
|
Q3 2018
|
1
|
|
$
|
0.88
|
|
Q4 2018
|
2
|
|
$
|
0.88
|
|
Total 2018
|
4
|
|
$
|
0.88
|
|
Butane Swaps
Priced as a Percentage of WTI
|
|
Volume
(mmgal)
|
|
Avg. NYMEX as
a
% of WTI Swaps
|
|
|
|
|
Q2 2018
|
1
|
|
70.5
|
%
|
Q3 2018
|
1
|
|
70.5
|
%
|
Q4 2018
|
2
|
|
70.5
|
%
|
Total 2018
|
4
|
|
70.5
|
%
|
Iso-Butane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q2 2018
|
2
|
|
$
|
0.92
|
|
Q3 2018
|
4
|
|
$
|
0.92
|
|
Q4 2018
|
4
|
|
$
|
0.92
|
|
Total 2018
|
10
|
|
$
|
0.92
|
|
Natural Gasoline
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q2 2018
|
10
|
|
$
|
1.42
|
|
Q3 2018
|
11
|
|
$
|
1.42
|
|
Q4 2018
|
12
|
|
$
|
1.42
|
|
Total 2018
|
33
|
|
$
|
1.42
|
|
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SOURCE Chesapeake Energy Corporation