OKLAHOMA CITY, Nov. 2, 2017 /PRNewswire/ -- Chesapeake
Energy Corporation (NYSE:CHK) today reported financial and
operational results for the 2017 third quarter plus other recent
developments. Highlights include:
- Average 2017 third quarter production of 541,600 boe per
day and average 2017 third quarter oil production of 86,000 barrels
per day, as previously announced
- Total production reached approximately 584,000 boe per
day, including 99,000 barrels of oil, on October 30, 2017
- On track to meet goal of averaging 100,000 barrels of oil
per day in the 2017 fourth quarter
- Upper Marcellus Shale enhanced completions yield rates
exceeding expectations; competitive with Lower Marcellus core
position
Doug Lawler, Chesapeake's Chief
Executive Officer, commented, "We continue to improve our capital
efficiency and cost structure as we drive toward free cash flow
neutrality. We have recognized greater productivity across our
diverse portfolio through technical innovation and the tenacity of
our employees and, accordingly, we are expanding our core position
in every operated play. On October 30,
2017, total production reached 584,000 boe per day,
including 99,000 barrels of oil and we remain on track to average
100,000 barrels of oil per day in the fourth quarter. As
further evidence of our progress, we are pleased to announce the
results of two new wells with enhanced completions in the Upper
Marcellus that are producing at rates of approximately 30 million
cubic feet of gas per day, exceeding expectations and competitive
with our world class Lower Marcellus position."
Lawler continued, "As we look toward 2018, our priorities remain
unchanged as we focus on further improving our balance sheet,
increasing our margins and driving toward cash flow neutrality.
While we have not announced details regarding our 2018 capital
program, we will maintain a disciplined approach that provides the
flexibility necessary to respond to changes in commodity prices.
As of today, we anticipate spending less capital in 2018 than
2017 and, given our asset quality and industry-leading capital
efficiency, we expect to deliver flat to modest production growth
on a lower capital expenditure. We look forward to reporting
more on our progress in the coming months."
2017 Third Quarter Results
For the 2017 third quarter, Chesapeake reported a net loss
available to common stockholders of $41
million, or $0.05 per diluted
share, while the company's EBITDA for the 2017 third quarter was
$345 million. Adjusting for
unrealized losses on commodity derivatives and other items that are
typically excluded by securities analysts, the 2017 third quarter
adjusted net income attributable to Chesapeake was $106 million, or $0.12 per diluted share, while the company's
adjusted EBITDA was $468 million.
Reconciliations of financial measures calculated in accordance with
GAAP to non-GAAP measures are provided on pages 12 – 18 of this
release.
Chesapeake's oil, natural gas and natural gas liquids (NGL)
unhedged revenue was approximately unchanged year over year despite
a 15% reduction in volume, mainly driven by asset sales.
Chesapeake's oil, natural gas and NGL unhedged revenue decreased 3%
quarter over quarter due to a decrease in the average commodity
prices for the company's natural gas production, partially offset
by an increase in natural gas and NGL production volumes sold.
Average daily production for the 2017 third quarter of
approximately 541,600 barrels of oil equivalent (boe) increased by
4% sequentially, adjusted for asset sales, and consisted of
approximately 86,000 barrels (bbls) of oil, 2.382 billion cubic
feet (bcf) of natural gas and 58,600 bbls of NGL.
Average production expenses during the 2017 third quarter were
$3.03 per boe, while general and
administrative (G&A) expenses (including stock-based
compensation) during the 2017 third quarter were $1.08 per boe. Combined production and G&A
expenses (including stock-based compensation) during the 2017 third
quarter were $4.11 per boe, an
increase of 6% year over year and a decrease of 6% quarter over
quarter. Gathering, processing and transportation expenses during
the 2017 third quarter were $7.40 per
boe, a decrease of 8% year over year and a nominal decrease quarter
over quarter.
Capital Spending Overview
Chesapeake's total capital investments were approximately
$692 million during the 2017 third
quarter, compared to approximately $667
million in the 2017 second quarter and $412 million in the 2016 third quarter. As a
result of the company's year-to-date capital investment, along with
its projected capital outlay in the 2017 fourth quarter,
Chesapeake's current guidance range for total capital investments
was raised to $2.3 to $2.5 billion
from $2.1 to $2.5 billion. A summary
of the company's guidance for 2017 is provided under "Management's
Outlook as of November 2, 2017,"
beginning on page 20.
|
2017
|
2017
|
2016
|
Operated activity
comparison
|
Q3
|
Q2
|
Q3
|
Average rig
count
|
17
|
|
19
|
|
11
|
|
Gross wells
spud
|
86
|
|
102
|
|
63
|
|
Gross wells
completed
|
120
|
|
107
|
|
80
|
|
Gross wells
connected
|
122
|
|
94
|
|
105
|
|
|
|
|
|
Type of cost ($ in
millions)
|
|
|
|
Drilling and
completion costs
|
$
|
626
|
|
$
|
596
|
|
$
|
332
|
|
Exploration costs,
leasehold and additions to other PP&E
|
17
|
|
24
|
|
21
|
|
Subtotal capital
expenditures
|
$
|
643
|
|
$
|
620
|
|
$
|
353
|
|
Capitalized
interest
|
49
|
|
47
|
|
59
|
|
Total capital
expenditures
|
$
|
692
|
|
$
|
667
|
|
$
|
412
|
|
Balance Sheet and Liquidity
As of September 30, 2017, Chesapeake's principal debt
balance was approximately $9.8
billion, compared to $10.0
billion as of December 31,
2016. The company's total liquidity as of September 30,
2017 was approximately $3.0 billion,
which included cash on hand and a borrowing capacity of
approximately $3.0 billion under the
company's senior secured revolving credit facility. As of
September 30, 2017, the company had $645 million of outstanding borrowings under the
revolving credit facility and had used $97
million of the revolving credit facility for various letters
of credit.
On October 12, 2017, Chesapeake
issued through a private placement an aggregate of $850 million of 8.00% Senior Notes due 2025 and
2027 with proceeds to be used to repurchase debt. On October 13, 2017, approximately $320 million principal amount of the company's
8.00% Senior Secured Second Lien Notes due 2022 and $193 million principal amount in various Senior
Notes due 2020 and 2021 were tendered. In addition, Chesapeake also
repurchased in the open market approximately $237 million principal amount of the company's
secured term loan due 2021 in October
2017. As a result, Chesapeake has further reduced the
principal amount of its secured debt by approximately $557 million since June
30, for a total reduction in the principal amount of secured
debt of approximately $1.2 billion
year to date. The company's total debt balance on October 31, 2017 was approximately $9.9 billion, including $643 million drawn on its revolving credit
facility and the company's total liquidity was approximately
$3.1 billion.
On October 30, 2017, the
administrative agent under the company's senior revolving credit
agreement, in addition to other lenders under the agreement,
notified Chesapeake that the borrowing base had been reaffirmed at
$3.785 billion.
Operations Update
Chesapeake's average daily production for the 2017 third quarter
was approximately 541,600 boe and is further detailed in the table
below. Chesapeake's projected production volumes and capital
expenditure program are subject to capital allocation decisions
throughout the remainder of the year and may be adjusted based on
prevailing market conditions.
|
2017
|
2017
|
2016
|
Operating area net
production (mboe/day)
|
Q3
|
Q2
|
Q3
|
Eagle Ford
|
93
|
100
|
101
|
Haynesville
|
134
|
121
|
139
|
Marcellus
|
126
|
135
|
134
|
Utica
|
120
|
97
|
127
|
Mid-Continent
|
56
|
59
|
55
|
Powder River
Basin
|
13
|
16
|
14
|
Barnett
|
—
|
—
|
59
|
Other
|
—
|
—
|
9
|
Total
production
|
542
|
528
|
638
|
Chesapeake is currently utilizing 14 drilling rigs (below the
2017 third quarter average of 17) across its operating areas, five
of which are located in the Eagle Ford Shale, three in the Powder
River Basin (PRB), three in the Haynesville Shale, two in Northeast
Appalachia and one in the Mid-Continent area. Chesapeake plans to
average 14 rigs in the 2017 fourth quarter.
In the Eagle Ford Shale, Chesapeake placed 31 wells on
production in the 2017 third quarter. Included in this number were
20 wells in the company's Faith Ranch development area, of which 14
wells reached peak production of more than 1,000 bbls of oil per
day. In total, the Faith Ranch wells achieved peak production of
approximately 18,000 bbls of oil per day. Additionally, in October,
Chesapeake placed 11 wells on production from its Vesper
development area, yielding approximately 13,000 bbls of oil
per day, highlighted by the Vesper Unit IV DIM H 3H well which
featured a three-mile lateral and enhanced completion, and yielded
an initial production of more than 2,000 bbls of oil per day.
Chesapeake expects to place on production up to 73 wells in the
Eagle Ford in the 2017 fourth quarter.
In the PRB, Chesapeake's third Turner well, the Graham 23-35-71
15H, was completed with a 4,500-foot lateral and placed on
production in September 2017,
achieving a peak rate of 1,737 boe per day (82% oil). On
October 31, 2017, Chesapeake placed
two additional Turner wells on production from its York pad,
averaging approximately 8,500 feet in lateral length each. The
company expects to provide updated results from these Turner wells
later in the month. Chesapeake added a third rig in October 2017 and expects to place on production
up to 11 wells in the 2017 fourth quarter, compared to seven wells
in the 2017 third quarter.
In the Marcellus Shale, Chesapeake has begun to deploy its
enhanced completion techniques on the Upper Marcellus formation,
yielding rates that have exceeded internal expectations. The
company placed two Upper Marcellus wells from its Maris pad located
in Susquehanna County on production in September 2017. These wells achieved peak rates
of 29,800 and 29,600 thousand cubic feet (mcf) of gas per day,
respectively, more than 50% higher than the company's previous
Upper Marcellus record rate of 18,700 mcf of gas per day from a
well drilled in 2015. These wells have produced with pressures as
expected with minimal depletion from offset wells in the Lower
Marcellus, including one that was offset at 375 feet. These results
confirmed positive delineation of the company's Upper Marcellus
resource potential in areas where Lower Marcellus production had
already existed, and have the potential to significantly increase
the company's core position in the play. Chesapeake also placed the
DPH SW WYO 3H well targeting the Lower Marcellus and located in the
southern edge of the company's Wyoming County acreage on
production, achieving a peak rate of 37,900 mcf of gas per day from
a 6,100-foot lateral with an enhanced completion in October 2017. Chesapeake expects to place on
production up to 17 wells in the 2017 fourth quarter, compared to
25 wells in the 2017 third quarter.
In the Utica Shale, enhanced completions techniques have yielded
an approximately 25% improvement in 120-day cumulative production
compared to the type curve. In July
2017, the eight-well Ellie pad was placed on production
yielding an average per well initial production rate of 1,100 boe
per day, 65% of which was liquids. The dry gas portion of the Utica
is also delivering positive results. Chesapeake is in the initial
flowback period for the Schiappa Trust A pad in Jefferson County and has seen initial
production rates of 20,000 mcf of gas per well per day. Chesapeake
plans to continue testing new completions designs in the 2017
fourth quarter.
In the Haynesville Shale, Chesapeake turned 12 wells on
production in the 2017 third quarter, averaging lateral lengths of
8,440 feet and initial production of 31,840 mcf of gas per day. Of
note, the company placed four wells from its BSNR pad located in De
Soto Parish on production in September
2017, averaging 9,800-foot laterals. While these wells
separately achieved peak rates ranging from 29,600 mcf to 37,200
mcf of gas per day, the combined peak rate from the BSNR pad
reached approximately 134,000 mcf of gas per day. In October, the
company also placed three wells from its PKY pad on production, all
with 8,500-foot laterals, which achieved a combined peak rate of
approximately 95,000 mcf of gas per day. As a result, last week
Chesapeake's net production from the Haynesville reached 1 bcf of
gas per day, which is the company's highest daily rate since
November 2012. Additionally,
Chesapeake expects to place on production its first 10,000-foot
Bossier well, the Nabors 13&12-10-13 1HC, located in Sabine Parish in late November 2017 and intends to spud its first
15,000-foot lateral Haynesville well in the 2017 fourth quarter.
The company expects to place on production up to seven wells in the
Haynesville in the 2017 fourth quarter.
In the Mid-Continent, Chesapeake recently drilled and completed
a 10,000-foot lateral well with an enhanced completion design on
the Bravo 1H well in Major County,
yielding an average production rate of approximately 1,550 bbls of
oil per day and an average total production rate of 1,960 boe per
day over the first 10 days.
Key Financial and
Operational Results
|
|
The table below
summarizes Chesapeake's key financial and operational results
during the 2017 third quarter compared to results in prior
periods.
|
|
|
|
Three Months
Ended
|
|
|
09/30/17
|
|
06/30/17
|
|
09/30/16
|
Oil equivalent
production (in mmboe)
|
|
50
|
|
|
48
|
|
|
59
|
|
Oil production (in
mmbbls)
|
|
8
|
|
|
8
|
|
|
8
|
|
Average realized oil
price ($/bbl)(a)
|
|
52.33
|
|
|
51.65
|
|
|
45.24
|
|
Natural gas
production (in bcf)
|
|
219
|
|
|
209
|
|
|
268
|
|
Average realized
natural gas price ($/mcf)(a)
|
|
2.52
|
|
|
2.71
|
|
|
2.13
|
|
NGL production (in
mmbbls)
|
|
5
|
|
|
5
|
|
|
6
|
|
Average realized NGL
price ($/bbl)(a)
|
|
21.26
|
|
|
18.51
|
|
|
13.70
|
|
Production expenses
($/boe)
|
|
3.03
|
|
|
2.92
|
|
|
2.80
|
|
Gathering, processing
and transportation expenses ($/boe)
|
|
7.40
|
|
|
7.44
|
|
|
8.07
|
|
Oil -
($/bbl)
|
|
4.33
|
|
|
3.70
|
|
|
3.67
|
|
Natural Gas -
($/mcf)
|
|
1.34
|
|
|
1.37
|
|
|
1.47
|
|
NGL -
($/bbl)
|
|
7.40
|
|
|
7.87
|
|
|
8.13
|
|
Production taxes
($/boe)
|
|
0.43
|
|
|
0.42
|
|
|
0.29
|
|
General and
administrative expenses ($/boe)(b)
|
|
0.91
|
|
|
1.20
|
|
|
0.90
|
|
Stock-based
compensation ($/boe)
|
|
0.17
|
|
|
0.25
|
|
|
0.18
|
|
DD&A of oil and
natural gas properties ($/boe)
|
|
4.57
|
|
|
4.21
|
|
|
4.26
|
|
DD&A of other
assets ($/boe)
|
|
0.41
|
|
|
0.43
|
|
|
0.42
|
|
Interest expense
($/boe)(a)
|
|
2.26
|
|
|
1.92
|
|
|
1.20
|
|
Marketing, gathering
and compression net margin ($ in millions)(c)
|
|
(14)
|
|
|
(25)
|
|
|
(162)
|
|
Net cash provided by
(used in) operating activities ($ in millions)
|
|
331
|
|
|
(157)
|
|
|
376
|
|
Net cash provided by
(used in) operating activities ($/boe)
|
|
6.62
|
|
|
(3.27)
|
|
|
6.37
|
|
Operating cash flow
($ in millions)(d)
|
|
337
|
|
|
316
|
|
|
214
|
|
Operating cash flow
($/boe)
|
|
6.74
|
|
|
6.58
|
|
|
3.63
|
|
Adjusted ebitda ($ in
millions)(e)
|
|
468
|
|
|
461
|
|
|
421
|
|
Adjusted ebitda
($/boe)
|
|
9.36
|
|
|
9.60
|
|
|
7.17
|
|
Net income (loss)
available to common stockholders ($ in millions)
|
|
(41)
|
|
|
470
|
|
|
(1,257)
|
|
Income (loss) per
share – diluted ($)
|
|
(0.05)
|
|
|
0.47
|
|
|
(1.62)
|
|
Adjusted net income
(loss) attributable to Chesapeake ($ in
millions)(f)
|
|
106
|
|
|
146
|
|
|
73
|
|
Adjusted income
(loss) per share - diluted ($)(g)
|
|
0.12
|
|
|
0.18
|
|
|
0.09
|
|
|
|
(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 for the three months ended
September 30, 2016, unrealized losses on supply contract
derivatives, but excludes depreciation and amortization of other
assets. For the three months ended September 30, 2016,
unrealized losses on supply contract derivatives were $280 million.
No other period presented had such gains (losses).
|
|
|
(d)
|
Defined as cash flow
provided by operating activities before changes in assets and
liabilities.
|
|
|
(e)
|
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 18.
|
|
|
(f)
|
Defined as net income
(loss) attributable to Chesapeake, as adjusted to remove the
effects of certain items detailed on pages 12 - 15.
|
|
|
(g)
|
Our presentation of
diluted adjusted net income (loss) per share excludes shares
considered antidilutive when calculating diluted earnings per share
in accordance with GAAP.
|
2017 Third Quarter Financial and Operational Results
Conference Call Information
A conference call to discuss this release has been scheduled on
Thursday, November 2, 2017 at
9:00 am EDT. The telephone number to
access the conference call is 719-785-1749 or toll-free
888-855-5428. The passcode for the call is 9224968. 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 9224968. 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. The company
also owns oil and natural gas marketing and natural gas compression
businesses.
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, general and administrative expenses,
capital expenditures, the timing of anticipated 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, processing and transportation commitments), 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; potential
challenges by Seventy Seven Energy Inc.'s (SSE) former creditors in
connection with SSE's recently completed bankruptcy under Chapter
11 of the U.S. Bankruptcy Code; an interruption in operations at
our headquarters due to a catastrophic event; the continuation of
suspended dividend payments on our common stock; the effectiveness
of our remediation plan for a material weakness; 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
|
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,
|
|
|
2017
|
|
2016
|
REVENUES:
|
|
|
|
|
Oil, natural gas and
NGL
|
|
$
|
979
|
|
|
$
|
1,177
|
|
Marketing, gathering
and compression
|
|
964
|
|
|
1,099
|
|
Total
Revenues
|
|
1,943
|
|
|
2,276
|
|
OPERATING
EXPENSES:
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
151
|
|
|
164
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
|
369
|
|
|
473
|
|
Production
taxes
|
|
21
|
|
|
17
|
|
Marketing, gathering
and compression
|
|
978
|
|
|
1,261
|
|
General and
administrative
|
|
54
|
|
|
63
|
|
Provision for legal
contingencies
|
|
20
|
|
|
8
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
228
|
|
|
251
|
|
Depreciation and
amortization of other assets
|
|
20
|
|
|
25
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
497
|
|
Impairments of fixed
assets and other
|
|
9
|
|
|
751
|
|
Net gains on sales of
fixed assets
|
|
(1)
|
|
|
—
|
|
Total Operating
Expenses
|
|
1,849
|
|
|
3,510
|
|
INCOME (LOSS) FROM
OPERATIONS
|
|
94
|
|
|
(1,234)
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
Interest
expense
|
|
(114)
|
|
|
(73)
|
|
Losses on
investments
|
|
—
|
|
|
(1)
|
|
Gains (losses) on
purchases or exchanges of debt
|
|
(1)
|
|
|
87
|
|
Other
income
|
|
4
|
|
|
7
|
|
Total Other Income
(Expense)
|
|
(111)
|
|
|
20
|
|
LOSS BEFORE INCOME
TAXES
|
|
(17)
|
|
|
(1,214)
|
|
Income Tax
Expense
|
|
—
|
|
|
—
|
|
NET
LOSS
|
|
(17)
|
|
|
(1,214)
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
(1)
|
|
NET LOSS
ATTRIBUTABLE TO CHESAPEAKE
|
|
(18)
|
|
|
(1,215)
|
|
Preferred stock
dividends
|
|
(23)
|
|
|
(42)
|
|
NET LOSS AVAILABLE
TO COMMON STOCKHOLDERS
|
|
$
|
(41)
|
|
|
$
|
(1,257)
|
|
LOSS PER COMMON
SHARE:
|
|
|
|
|
Basic
|
|
$
|
(0.05)
|
|
|
$
|
(1.62)
|
|
Diluted
|
|
$
|
(0.05)
|
|
|
$
|
(1.62)
|
|
WEIGHTED AVERAGE
COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
Basic
|
|
909
|
|
|
777
|
|
Diluted
|
|
909
|
|
|
777
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions except per share data)
(unaudited)
|
|
|
Nine Months
Ended
September 30,
|
|
|
2017
|
|
2016
|
REVENUES:
|
|
|
|
|
Oil, natural gas and
NGL
|
|
$
|
3,727
|
|
|
$
|
2,610
|
|
Marketing, gathering
and compression
|
|
3,250
|
|
|
3,241
|
|
Total
Revenues
|
|
6,977
|
|
|
5,851
|
|
OPERATING
EXPENSES:
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
426
|
|
|
552
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
|
1,081
|
|
|
1,436
|
|
Production
taxes
|
|
64
|
|
|
54
|
|
Marketing, gathering
and compression
|
|
3,333
|
|
|
3,410
|
|
General and
administrative
|
|
189
|
|
|
172
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
3
|
|
Provision for legal
contingencies
|
|
35
|
|
|
112
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
627
|
|
|
791
|
|
Depreciation and
amortization of other assets
|
|
62
|
|
|
83
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
2,564
|
|
Impairments of fixed
assets and other
|
|
426
|
|
|
795
|
|
Net gains on sales of
fixed assets
|
|
—
|
|
|
(5)
|
|
Total Operating
Expenses
|
|
6,243
|
|
|
9,967
|
|
INCOME (LOSS) FROM
OPERATIONS
|
|
734
|
|
|
(4,116)
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
Interest
expense
|
|
(302)
|
|
|
(197)
|
|
Losses on
investments
|
|
—
|
|
|
(3)
|
|
Loss on sale of
investment
|
|
—
|
|
|
(10)
|
|
Gains on purchases or
exchanges of debt
|
|
183
|
|
|
255
|
|
Other
income
|
|
6
|
|
|
13
|
|
Total Other Income
(Expense)
|
|
(113)
|
|
|
58
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
|
621
|
|
|
(4,058)
|
|
Income Tax
Expense
|
|
2
|
|
|
—
|
|
NET INCOME
(LOSS)
|
|
619
|
|
|
(4,058)
|
|
Net income
attributable to noncontrolling interests
|
|
(3)
|
|
|
(1)
|
|
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
|
|
616
|
|
|
(4,059)
|
|
Preferred stock
dividends
|
|
(62)
|
|
|
(127)
|
|
Loss on exchange of
preferred stock
|
|
(41)
|
|
|
—
|
|
Earnings allocated to
participating securities
|
|
(7)
|
|
|
—
|
|
NET INCOME (LOSS)
AVAILABLE TO COMMON STOCKHOLDERS
|
|
$
|
506
|
|
|
$
|
(4,186)
|
|
EARNINGS (LOSS)
PER COMMON SHARE:
|
|
|
|
|
Basic
|
|
$
|
0.56
|
|
|
$
|
(5.80)
|
|
Diluted
|
|
$
|
0.56
|
|
|
$
|
(5.80)
|
|
WEIGHTED AVERAGE
COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
Basic
|
|
908
|
|
|
722
|
|
Diluted
|
|
908
|
|
|
722
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
($ in
millions)
(unaudited)
|
|
|
September 30,
2017
|
|
December 31,
2016
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
5
|
|
|
$
|
882
|
|
Other current
assets
|
|
1,173
|
|
|
1,260
|
|
Total Current
Assets
|
|
1,178
|
|
|
2,142
|
|
|
|
|
|
|
Property and
equipment, net
|
|
10,580
|
|
|
10,609
|
|
Other
assets
|
|
223
|
|
|
277
|
|
Total
Assets
|
|
$
|
11,981
|
|
|
$
|
13,028
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
2,218
|
|
|
$
|
3,648
|
|
Long-term debt,
net
|
|
9,899
|
|
|
9,938
|
|
Other long-term
liabilities
|
|
568
|
|
|
645
|
|
Total
Liabilities
|
|
12,685
|
|
|
14,231
|
|
|
|
|
|
|
Preferred
stock
|
|
1,671
|
|
|
1,771
|
|
Noncontrolling
interests
|
|
253
|
|
|
257
|
|
Common stock and
other stockholders' equity (deficit)
|
|
(2,628)
|
|
|
(3,231)
|
|
Total Equity
(Deficit)
|
|
(704)
|
|
|
(1,203)
|
|
|
|
|
|
|
Total Liabilities and
Equity
|
|
$
|
11,981
|
|
|
$
|
13,028
|
|
|
|
|
|
|
Common shares
outstanding (in millions)
|
|
909
|
|
|
896
|
|
Principal amount of
debt outstanding
|
|
$
|
9,775
|
|
|
$
|
9,989
|
|
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,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net
Production:
|
|
|
|
|
|
|
|
|
Oil
(mmbbl)
|
|
8
|
|
|
8
|
|
|
23
|
|
|
25
|
|
Natural gas
(bcf)
|
|
219
|
|
|
268
|
|
|
639
|
|
|
814
|
|
NGL
(mmbbl)
|
|
5
|
|
|
6
|
|
|
15
|
|
|
19
|
|
Oil equivalent
(mmboe)
|
|
50
|
|
|
59
|
|
|
145
|
|
|
180
|
|
Oil, natural gas
and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
379
|
|
|
$
|
342
|
|
|
$
|
1,140
|
|
|
$
|
952
|
|
Oil derivatives –
realized gains (losses)(a)
|
|
35
|
|
|
18
|
|
|
79
|
|
|
102
|
|
Oil derivatives –
unrealized gains (losses)(a)
|
|
(96)
|
|
|
23
|
|
|
45
|
|
|
(217)
|
|
Total oil
sales
|
|
318
|
|
|
383
|
|
|
1,264
|
|
|
837
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
553
|
|
|
622
|
|
|
1,807
|
|
|
1,545
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
|
(1)
|
|
|
(50)
|
|
|
(53)
|
|
|
192
|
|
Natural gas
derivatives – unrealized gains (losses)(a)
|
|
(3)
|
|
|
131
|
|
|
384
|
|
|
(204)
|
|
Total natural gas
sales
|
|
549
|
|
|
703
|
|
|
2,138
|
|
|
1,533
|
|
|
|
|
|
|
|
|
|
|
NGL sales
|
|
117
|
|
|
84
|
|
|
328
|
|
|
247
|
|
NGL derivatives –
realized gains (losses)(a)
|
|
(3)
|
|
|
(2)
|
|
|
(1)
|
|
|
(5)
|
|
NGL derivatives –
unrealized gains (losses)(a)
|
|
(2)
|
|
|
9
|
|
|
(2)
|
|
|
(2)
|
|
Total NGL
sales
|
|
112
|
|
|
91
|
|
|
325
|
|
|
240
|
|
|
|
|
|
|
|
|
|
|
Total oil, natural
gas and NGL sales
|
|
$
|
979
|
|
|
$
|
1,177
|
|
|
$
|
3,727
|
|
|
$
|
2,610
|
|
Average Sales
Price
(excluding
gains (losses) on derivatives):
|
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
47.94
|
|
|
$
|
42.94
|
|
|
$
|
48.53
|
|
|
$
|
38.21
|
|
Natural gas ($ per
mcf)
|
|
$
|
2.52
|
|
|
$
|
2.32
|
|
|
$
|
2.83
|
|
|
$
|
1.90
|
|
NGL ($ per
bbl)
|
|
$
|
21.83
|
|
|
$
|
13.93
|
|
|
$
|
21.28
|
|
|
$
|
12.90
|
|
Oil equivalent ($ per
boe)
|
|
$
|
21.06
|
|
|
$
|
17.86
|
|
|
$
|
22.53
|
|
|
$
|
15.27
|
|
Average Sales
Price
(including
realized gains (losses) on derivatives):
|
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
|
$
|
52.33
|
|
|
$
|
45.24
|
|
|
$
|
51.90
|
|
|
$
|
42.31
|
|
Natural gas ($ per
mcf)
|
|
$
|
2.52
|
|
|
$
|
2.13
|
|
|
$
|
2.75
|
|
|
$
|
2.13
|
|
NGL ($ per
bbl)
|
|
$
|
21.26
|
|
|
$
|
13.70
|
|
|
$
|
21.21
|
|
|
$
|
12.66
|
|
Oil equivalent ($ per
boe)
|
|
$
|
21.67
|
|
|
$
|
17.30
|
|
|
$
|
22.70
|
|
|
$
|
16.88
|
|
Interest Expense
($ in millions):
|
|
|
|
|
|
|
|
|
Interest
expense(b)
|
|
$
|
115
|
|
|
$
|
74
|
|
|
$
|
302
|
|
|
$
|
199
|
|
Interest rate
derivatives – realized (gains) losses(c)
|
|
(1)
|
|
|
(3)
|
|
|
(3)
|
|
|
(9)
|
|
Interest rate
derivatives – unrealized (gains) losses(c)
|
|
—
|
|
|
2
|
|
|
3
|
|
|
7
|
|
Total Interest
Expense
|
|
$
|
114
|
|
|
$
|
73
|
|
|
$
|
302
|
|
|
$
|
197
|
|
|
|
(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 and 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 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,
2017
|
|
September 30,
2016
|
|
|
|
|
|
Beginning
cash
|
|
$
|
13
|
|
|
$
|
4
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
331
|
|
|
376
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(566)
|
|
|
(339)
|
|
Acquisitions of
proved and unproved properties(b)
|
|
(64)
|
|
|
(157)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
242
|
|
|
24
|
|
Additions to other
property and equipment(c)
|
|
(5)
|
|
|
(7)
|
|
Proceeds from sales
of other property and equipment
|
|
14
|
|
|
—
|
|
Other
|
|
—
|
|
|
(1)
|
|
Net cash used in
investing activities
|
|
(379)
|
|
|
(480)
|
|
|
|
|
|
|
Net cash provided
by financing activities
|
|
40
|
|
|
104
|
|
Change in cash and
cash equivalents
|
|
(8)
|
|
|
—
|
|
Ending
cash
|
|
$
|
5
|
|
|
$
|
4
|
|
|
|
(a)
|
Includes capitalized
interest of $2 million and $1 million for the three months ended
September 30, 2017 and 2016, respectively.
|
|
|
(b)
|
Includes capitalized
interest of $47 million and $56 million for the three months ended
September 30, 2017 and 2016, respectively.
|
|
|
(c)
|
Includes capitalized
interest of a nominal amount for the three months ended
September 30, 2017 and 2016, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
|
NINE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
Beginning
cash
|
|
$
|
882
|
|
|
$
|
825
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
273
|
|
|
50
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(1,597)
|
|
|
(948)
|
|
Acquisitions of
proved and unproved properties(b)
|
|
(226)
|
|
|
(583)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
1,193
|
|
|
988
|
|
Additions to other
property and equipment(c)
|
|
(12)
|
|
|
(32)
|
|
Proceeds from sales
of other property and equipment
|
|
40
|
|
|
70
|
|
Cash paid for title
defects
|
|
—
|
|
|
(69)
|
|
Other
|
|
—
|
|
|
(5)
|
|
Net cash used in
investing activities
|
|
(602)
|
|
|
(579)
|
|
|
|
|
|
|
Net cash used in
financing activities
|
|
(548)
|
|
|
(292)
|
|
Change in cash and
cash equivalents
|
|
(877)
|
|
|
(821)
|
|
Ending
cash
|
|
$
|
5
|
|
|
$
|
4
|
|
|
|
(a)
|
Includes capitalized
interest of $7 million and $5 million for the nine months ended
September 30, 2017 and 2016, respectively.
|
|
|
(b)
|
Includes capitalized
interest of $139 million and $179 million for the nine months ended
September 30, 2017 and 2016, respectively.
|
|
|
(c)
|
Includes capitalized
interest of $1 million and $1 million for the nine months ended
September 30, 2017 and 2016, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS
($ in millions except per share data)
(unaudited)
|
THREE MONTHS
ENDED:
|
|
September 30,
2017
|
|
|
$
|
|
$/Diluted
Share(b)(c)
|
Net loss available
to common stockholders (GAAP)
|
|
$
|
(41)
|
|
|
$
|
(0.05)
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized losses on
commodity derivatives
|
|
101
|
|
|
0.12
|
|
Provision for legal
contingencies
|
|
20
|
|
|
0.02
|
|
Impairments of fixed
assets and other
|
|
9
|
|
|
0.01
|
|
Net gains on sales of
fixed assets
|
|
(1)
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
1
|
|
|
—
|
|
Income tax expense
(benefit)(a)
|
|
—
|
|
|
—
|
|
Other
|
|
(6)
|
|
|
(0.01)
|
|
Adjusted net
income available to common
stockholders(b) (Non-GAAP)
|
|
83
|
|
|
0.09
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
0.03
|
|
Total adjusted net
income attributable to Chesapeake(b) (c)
(Non-GAAP)
|
|
$
|
106
|
|
|
$
|
0.12
|
|
|
|
(a)
|
Due to our valuation
allowance position, no income tax effect from the adjustments has
been included in determining adjusted net income.
|
|
|
(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
accounting principles generally accepted in the United States
(GAAP), and should not be considered as an alternative to 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.
|
|
|
(c)
|
Our presentation of
diluted adjusted net income (loss) per share excludes 206 million
shares considered antidilutive when calculating diluted 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)
|
THREE MONTHS
ENDED:
|
|
September 30,
2016
|
|
|
$
|
|
$/Diluted
Share(b)(c)
|
Net loss available
to common stockholders (GAAP)
|
|
$
|
(1,257)
|
|
|
$
|
(1.62)
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized gains on
commodity derivatives
|
|
(163)
|
|
|
(0.21)
|
|
Unrealized losses on
supply contract derivatives
|
|
280
|
|
|
0.36
|
|
Provision for legal
contingencies
|
|
8
|
|
|
0.01
|
|
Impairment of natural
gas properties
|
|
497
|
|
|
0.64
|
|
Impairments of fixed
assets and other
|
|
751
|
|
|
0.97
|
|
Gains on purchases or
exchanges of debt
|
|
(87)
|
|
|
(0.11)
|
|
Income tax expense
(benefit)(a)
|
|
—
|
|
|
—
|
|
Other
|
|
2
|
|
|
—
|
|
Adjusted net
income available to common
stockholders(b) (Non-GAAP)
|
|
31
|
|
|
0.04
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
42
|
|
|
0.05
|
|
Total adjusted net
income attributable to Chesapeake(b) (c)
(Non-GAAP)
|
|
$
|
73
|
|
|
$
|
0.09
|
|
|
|
(a)
|
Due to our valuation
allowance position, no income tax effect from the adjustments has
been included in determining adjusted net income.
|
|
|
(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
accounting principles generally accepted in the United States
(GAAP), and should not be considered as an alternative to 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.
|
|
|
(c)
|
Our presentation of
diluted adjusted net income (loss) per share excludes 113 million
shares considered antidilutive when calculating diluted 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,
2017
|
|
|
$
|
|
$/Diluted
Share(b)(c)
|
Net income
available to common stockholders (GAAP)
|
|
$
|
506
|
|
|
$
|
0.56
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized gains on
commodity derivatives
|
|
(427)
|
|
|
(0.47)
|
|
Provision for legal
contingencies
|
|
35
|
|
|
0.04
|
|
Impairments of fixed
assets and other
|
|
426
|
|
|
0.47
|
|
Gains on purchases or
exchanges of debt
|
|
(183)
|
|
|
(0.21)
|
|
Loss on exchange of
preferred stock
|
|
41
|
|
|
0.05
|
|
Income tax expense
(benefit)(a)
|
|
—
|
|
|
—
|
|
Other
|
|
(3)
|
|
|
—
|
|
Adjusted net
income available to common
stockholders(b) (Non-GAAP)
|
|
395
|
|
|
0.44
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
62
|
|
|
0.07
|
|
Earnings allocated to
participating securities
|
|
7
|
|
|
—
|
|
Total adjusted net
income attributable to Chesapeake(b)
(c) (Non-GAAP)
|
|
$
|
464
|
|
|
$
|
0.51
|
|
|
|
(a)
|
Due to our valuation
allowance position, no income tax effect from the adjustments has
been included in determining adjusted net income.
|
|
|
(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
accounting principles generally accepted in the United States
(GAAP), and should not be considered as an alternative to 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.
|
|
|
(c)
|
Our presentation of
diluted adjusted net income (loss) per share excludes 207 million
shares considered antidilutive when calculating diluted 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,
2016
|
|
|
$
|
|
$/Diluted
Share(b)(c)
|
Net loss available
to common stockholders (GAAP)
|
|
$
|
(4,186)
|
|
|
(5.80)
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized losses on
commodity derivatives
|
|
423
|
|
|
0.58
|
|
Unrealized losses on
supply contract derivatives
|
|
297
|
|
|
0.41
|
|
Restructuring and
other termination costs
|
|
3
|
|
|
—
|
|
Provision for legal
contingencies
|
|
112
|
|
|
0.16
|
|
Impairment of natural
gas properties
|
|
2,564
|
|
|
3.56
|
|
Impairments of fixed
assets and other
|
|
795
|
|
|
1.10
|
|
Net gains on sales of
fixed assets
|
|
(5)
|
|
|
(0.01)
|
|
Loss on sale of
investment
|
|
10
|
|
|
0.01
|
|
Gains on purchases or
exchanges of debt
|
|
(255)
|
|
|
(0.35)
|
|
Income tax expense
(benefit)(a)
|
|
—
|
|
|
—
|
|
Other
|
|
8
|
|
|
0.01
|
|
Adjusted net loss
available to common
stockholders(b) (Non-GAAP)
|
|
(234)
|
|
|
(0.33)
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
127
|
|
|
0.18
|
|
Total adjusted net
loss attributable to Chesapeake(b)
(c) (Non-GAAP)
|
|
$
|
(107)
|
|
|
$
|
(0.15)
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Due to our valuation
allowance position, no income tax effect from the adjustments has
been included in determining adjusted net income.
|
|
|
(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
accounting principles generally accepted in the United States
(GAAP), and should not be considered as an alternative to 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.
|
|
|
(c)
|
Our presentation of
diluted adjusted net income (loss) per share excludes 113 million
shares considered antidilutive when calculating diluted 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,
2017
|
|
September 30,
2016
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
331
|
|
|
$
|
376
|
|
Changes in assets and
liabilities
|
|
6
|
|
|
(162)
|
|
OPERATING CASH
FLOW(a)
|
|
$
|
337
|
|
|
$
|
214
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
NET
LOSS
|
|
$
|
(17)
|
|
|
$
|
(1,214)
|
|
Interest
expense
|
|
114
|
|
|
73
|
|
Depreciation and
amortization of other assets
|
|
20
|
|
|
25
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
228
|
|
|
251
|
|
EBITDA(b)
|
|
$
|
345
|
|
|
$
|
(865)
|
|
THREE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
331
|
|
|
$
|
376
|
|
Changes in assets and
liabilities
|
|
6
|
|
|
(162)
|
|
Interest expense, net
of unrealized gains (losses) on derivatives
|
|
114
|
|
|
71
|
|
Gains (losses) on
commodity derivatives, net
|
|
(70)
|
|
|
129
|
|
Losses on supply
contract derivatives, net
|
|
—
|
|
|
(134)
|
|
Cash receipts on
commodity and supply contract derivative
settlements, net
|
|
(20)
|
|
|
(101)
|
|
Renegotiation of gas
gathering contract
|
|
—
|
|
|
66
|
|
Stock-based
compensation
|
|
(11)
|
|
|
(15)
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
1
|
|
Provision for legal
contingencies
|
|
(20)
|
|
|
27
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
(497)
|
|
Impairments of fixed
assets and other
|
|
(8)
|
|
|
(751)
|
|
Net gains on sales of
fixed assets
|
|
1
|
|
|
—
|
|
Investment
activity
|
|
—
|
|
|
(1)
|
|
Gains on purchases or
exchanges of debt
|
|
—
|
|
|
87
|
|
Other
items
|
|
22
|
|
|
39
|
|
EBITDA(b)
|
|
$
|
345
|
|
|
$
|
(865)
|
|
|
|
(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 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 flows
from 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,
2017
|
|
September 30,
2016
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES
|
|
$
|
273
|
|
|
$
|
50
|
|
Changes in assets and
liabilities
|
|
366
|
|
|
614
|
|
OPERATING CASH
FLOW(a)
|
|
$
|
639
|
|
|
$
|
664
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
NET INCOME
(LOSS)
|
|
$
|
619
|
|
|
$
|
(4,058)
|
|
Interest
expense
|
|
302
|
|
|
197
|
|
Income tax
expense
|
|
2
|
|
|
—
|
|
Depreciation and
amortization of other assets
|
|
62
|
|
|
83
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
627
|
|
|
791
|
|
EBITDA(b)
|
|
$
|
1,612
|
|
|
$
|
(2,987)
|
|
NINE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
CASH USED IN
OPERATING ACTIVITIES
|
|
$
|
273
|
|
|
$
|
50
|
|
Changes in assets and
liabilities
|
|
366
|
|
|
614
|
|
Interest expense, net
of unrealized gains (losses) on derivatives
|
|
299
|
|
|
190
|
|
Gains (losses) on
commodity derivatives, net
|
|
452
|
|
|
(134)
|
|
Losses on supply
contract derivatives, net
|
|
—
|
|
|
(151)
|
|
Cash (receipts)
payments on commodity and supply contract derivative settlements, net
|
|
46
|
|
|
(487)
|
|
Renegotiation of gas
gathering contract
|
|
—
|
|
|
66
|
|
Stock-based
compensation
|
|
(38)
|
|
|
(40)
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
(1)
|
|
Provision for legal
contingencies
|
|
(35)
|
|
|
(77)
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
(2,564)
|
|
Impairments of fixed
assets and other
|
|
(9)
|
|
|
(785)
|
|
Net gains on sales of
fixed assets
|
|
—
|
|
|
5
|
|
Investment
activity
|
|
—
|
|
|
(13)
|
|
Gains on purchases or
exchanges of debt
|
|
185
|
|
|
255
|
|
Other
items
|
|
73
|
|
|
85
|
|
EBITDA(b)
|
|
$
|
1,612
|
|
|
$
|
(2,987)
|
|
|
|
(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 activities as an indicator
of cash flows, or as a measure of liquidity. Operating cash flow
for the nine months ended September 30, 2017 includes $290
million paid to assign an oil transportation agreement to a third
party and $126 million paid to terminate future natural gas
transportation commitments.
|
|
|
(b)
|
EBITDA represents net
income before interest expense, income taxes, and depreciation,
depletion and amortization expense. EBITDA is presented as a
supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information
regarding our ability to meet our future debt service, capital
expenditures and working capital requirements. This measure is
widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
EBITDA is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreements and is used in the financial covenants in
our bank credit agreements. EBITDA is not a measure of financial
performance under GAAP. Accordingly, it should not be considered as
a substitute for net income, income from operations or cash flows
from operating activities prepared in accordance with
GAAP.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
|
THREE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
EBITDA
|
|
$
|
345
|
|
|
$
|
(865)
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized (gains)
losses on commodity derivatives
|
|
101
|
|
|
(163)
|
|
Unrealized losses on
supply contract derivatives
|
|
—
|
|
|
280
|
|
Provision for legal
contingencies
|
|
20
|
|
|
8
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
497
|
|
Impairments of fixed
assets and other
|
|
9
|
|
|
751
|
|
Net gains on sales of
fixed assets
|
|
(1)
|
|
|
—
|
|
(Gains) losses on
purchases or exchanges of debt
|
|
1
|
|
|
(87)
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
(1)
|
|
Other
|
|
(6)
|
|
|
1
|
|
|
|
|
|
|
Adjusted
EBITDA(a)
|
|
$
|
468
|
|
|
$
|
421
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
|
NINE MONTHS
ENDED:
|
|
September 30,
2017
|
|
September 30,
2016
|
|
|
|
|
|
EBITDA
|
|
$
|
1,612
|
|
|
$
|
(2,987)
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
Unrealized (gains)
losses on commodity derivatives
|
|
(427)
|
|
|
423
|
|
Unrealized losses on
supply contract derivatives
|
|
—
|
|
|
297
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
3
|
|
Provision for legal
contingencies
|
|
35
|
|
|
112
|
|
Impairment of oil and
natural gas properties
|
|
—
|
|
|
2,564
|
|
Impairments of fixed
assets and other
|
|
426
|
|
|
795
|
|
Net gains on sales of
fixed assets
|
|
—
|
|
|
(5)
|
|
Loss on sale of
investment
|
|
—
|
|
|
10
|
|
Gains on purchases or
exchanges of debt
|
|
(183)
|
|
|
(255)
|
|
Net income
attributable to noncontrolling interests
|
|
(3)
|
|
|
(1)
|
|
Other
|
|
(6)
|
|
|
(1)
|
|
|
|
|
|
|
Adjusted
EBITDA(a)
|
|
$
|
1,454
|
|
|
$
|
955
|
|
|
|
(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
RECONCILIATION OF
PV-9 AND PV-10 TO STANDARDIZED MEASURE
($ in
millions)
(unaudited)
|
|
PV-9 is a non-GAAP
metric used in the determination of the value of collateral under
Chesapeake's credit facility. PV-10 is a non-GAAP metric used by
the industry, investors and analysts to estimate the present value,
discounted at 10% per annum, of estimated future cash flows of the
company's estimated proved reserves before income tax. The
following table shows the reconciliation of PV-9 and PV-10 to the
company's standardized measure of discounted future net cash flows,
the most directly comparable GAAP measure, for the year ended
December 31, 2016 and for the interim period ended September 30,
2017. Management believes that PV-9 provides useful information to
investors regarding the company's collateral position and that
PV-10 provides useful information to investors because it is widely
used by professional analysts and sophisticated investors in
evaluating oil and natural gas companies. Because there are many
unique factors that can impact an individual company when
estimating the amount of future income taxes to be paid, management
believes the use of a pre-tax measure is valuable for evaluating
the company. Neither PV-9 nor PV-10 should be considered as an
alternative to the standardized measure of discounted future net
cash flows as computed under GAAP. With respect to PV-9 and PV-10
calculated as of an interim date, it is not practical to calculate
taxes for the related interim period because GAAP does not provide
for disclosure of standardized measure on an interim
basis.
|
|
|
|
PV-9 – September 30,
2017 @ NYMEX Strip
|
|
$
|
8,456
|
|
Less: Change in
discount factor from 9 to 10
|
|
(440)
|
|
PV-10 – September 30,
2017 @ NYMEX Strip
|
|
8,016
|
|
Less: Change in
pricing assumption from NYMEX Strip to SEC
|
|
(85)
|
|
PV-10 – September 30,
2017 @ SEC
|
|
7,931
|
|
Less: Change in PV-10
from 12/31/16 to 9/30/2017
|
|
(3,526)
|
|
PV-10 – December 31,
2016 @ SEC
|
|
4,405
|
|
Less: Present value
of future income tax discounted at 10%
|
|
(26)
|
|
Standardized measure
of discounted future cash flows – December 31, 2016
|
|
$
|
4,379
|
|
CHESAPEAKE ENERGY
CORPORATION
|
MANAGEMENT'S
OUTLOOK AS OF NOVEMBER 2, 2017
|
|
Chesapeake
periodically provides guidance on certain factors that affect the
company's future financial performance. New information or changes
from the company's September 26, 2017 Outlook are italicized
bold below.
|
|
|
Year
Ending
12/31/2017
|
|
|
Adjusted Production
Growth(a)
|
(1%) to 1%
|
Absolute
Production
|
|
Liquids -
mmbbls
|
51.5 -
53.5
|
Oil -
mmbbls
|
32.0 -
33.0
|
NGL -
mmbbls
|
19.5 -
20.5
|
Natural gas -
bcf
|
855 - 875
|
Total absolute
production - mmboe
|
194.0 -
199.0
|
Absolute daily rate -
mboe
|
532 - 545
|
Estimated
Realized Hedging Effects(b) (based on 10/30/17 strip
prices):
|
|
Oil -
$/bbl
|
$2.61
|
Natural gas -
$/mcf
|
$0.00
|
NGL -
$/bbl
|
($0.20)
|
Estimated Basis to
NYMEX Prices:
|
|
Oil -
$/bbl
|
$0.45 -
$0.55
|
Natural gas -
$/mcf
|
$0.30 -
$0.35
|
NGL -
$/bbl
|
$3.75 -
$4.15
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$2.80 -
$2.95
|
Gathering,
processing and transportation expenses
|
$7.15 -
$7.40
|
Oil -
$/bbl
|
$3.90 -
$4.00
|
Natural Gas -
$/mcf
|
$1.30 -
$1.35
|
NGL -
$/bbl
|
$7.70 -
$7.90
|
Production
taxes
|
$0.40 -
$0.50
|
General and
administrative(c)
|
$1.10 -
$1.20
|
Stock-based
compensation (noncash)
|
$0.10 -
$0.20
|
DD&A of natural
gas and liquids assets
|
$4.00 -
$5.00
|
Depreciation of other
assets
|
$0.40 -
$0.50
|
Interest
expense(d)
|
$2.05 -
$2.15
|
Marketing, gathering
and compression net margin(e)
|
($80) -
($60)
|
Book Tax
Rate
|
0%
|
Capital
Expenditures ($ in millions)(f)
|
$2,100 -
$2,300
|
Capitalized Interest
($ in millions)
|
$200
|
Total Capital
Expenditures ($ in millions)
|
$2,300 -
$2,500
|
|
|
(a)
|
Based on 2016
production of 529 mboe per day, adjusted for 2016 and 2017
sales.
|
|
|
(b)
|
Includes expected
settlements for commodity 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.
|
|
|
(d)
|
Excludes unrealized
gains (losses) on interest rate derivatives.
|
|
|
(e)
|
Excludes non-cash
amortization of approximately $22 million related to the buydown of
a transportation agreement.
|
|
|
(f)
|
Includes capital
expenditures for drilling and completion, leasehold, geological and
geophysical costs, rig termination payments and other property and
plant and equipment. Excludes any additional proved property
acquisitions.
|
Oil, Natural Gas and Natural Gas Liquids Hedging
Activities
Chesapeake enters into commodity 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 October 31, 2017, the
company had downside protection, through open swaps, on a portion
of its remaining 2017 oil production at an average price of
$50.36 per bbl. The company had
downside price protection, through open swaps and two-way collars,
on a portion of its remaining 2017 natural gas production at an
average price of $3.17 per mcf.
Chesapeake also had downside price protection, through open swaps,
on a portion of its remaining 2017 propane production at an average
price of $0.76 per gallon.
In addition, the company had downside protection, through open
swaps and two-way collars, on a portion of its 2018 natural gas
production at an average price of $3.10 per mcf. Chesapeake also had downside price
protection through open swaps on a portion of its 2018 oil
production at an average price of $51.74 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 $39.15 per bbl.
The company's crude oil hedging positions as of October 31, 2017 were as follows:
Open Crude Oil
Swaps
Gains (Losses)
from Closed Crude Oil Trades
|
|
Open
Swaps
(mbbls)
|
|
Avg.
NYMEX
Price
of
Open
Swaps
|
|
Gains/Losses
from Closed
Trades
($ in
millions)
|
|
|
|
|
|
|
Q4 2017
|
5,612
|
|
|
$
|
50.36
|
|
|
23
|
|
Total 2017
|
5,612
|
|
|
$
|
50.36
|
|
|
$
|
23
|
|
|
|
|
|
|
|
Q1 2018
|
5,099
|
|
|
$
|
51.84
|
|
|
$
|
(1)
|
|
Q2 2018
|
5,187
|
|
|
$
|
51.85
|
|
|
(1)
|
|
Q3 2018
|
4,324
|
|
|
$
|
51.63
|
|
|
(1)
|
|
Q4 2018
|
4,324
|
|
|
$
|
51.63
|
|
|
(1)
|
|
Total 2018
|
18,934
|
|
|
$
|
51.74
|
|
|
$
|
(4)
|
|
|
|
|
|
|
|
Total 2019 -
2022
|
—
|
|
|
$
|
—
|
|
|
$
|
(8)
|
|
Crude Oil Net
Written Call Options
|
|
Call
Options
(mbbls)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q4 2017
|
1,334
|
|
$
|
83.50
|
|
Total 2017
|
1,334
|
|
$
|
83.50
|
|
|
|
|
|
Q3 2018
|
920
|
|
$
|
52.87
|
|
Q4 2018
|
920
|
|
$
|
52.87
|
|
Total 2018
|
1,840
|
|
$
|
52.87
|
|
Crude Oil
Three-Way Collars
|
|
|
Open Collars
(mmbbls)
|
|
Avg. NYMEX
Sold Put Price
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
|
Q1 2018
|
|
450
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
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
|
|
1,825
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q4 2017
|
1
|
|
$
|
3.15
|
|
Total 2017
|
1
|
|
$
|
3.15
|
|
|
|
|
|
Q1 2018
|
2
|
|
$
|
3.12
|
|
Q1 2018
|
2
|
|
$
|
3.12
|
|
Q3 2018
|
2
|
|
$
|
3.28
|
|
Q4 2018
|
2
|
|
$
|
3.28
|
|
Total 2018
|
8
|
|
$
|
3.19
|
|
The company's natural gas hedging positions as of October 31, 2017 were as follows:
Open Natural Gas
Swaps
Losses from Closed
Natural Gas Trades
|
|
Open
Swaps
(bcf)
|
|
Avg.
NYMEX
Price
of
Open
Swaps
|
|
Losses
from Closed
Trades
($ in
millions)
|
|
|
|
|
|
|
Q4 2017
|
164
|
|
$
|
3.16
|
|
|
(3)
|
|
Total 2017
|
164
|
|
$
|
3.16
|
|
|
$
|
(3)
|
|
|
|
|
|
|
|
Q1 2018
|
174
|
|
$
|
3.44
|
|
|
$
|
(6)
|
|
Q1 2018
|
118
|
|
$
|
2.92
|
|
|
(4)
|
|
Q3 2018
|
120
|
|
$
|
2.94
|
|
|
(4)
|
|
Q4 2018
|
120
|
|
$
|
3.00
|
|
|
(6)
|
|
Total 2018
|
532
|
|
$
|
3.11
|
|
|
$
|
(20)
|
|
|
|
|
|
|
|
Total 2019 -
2022
|
—
|
|
|
$
|
—
|
|
|
$
|
(49)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Two-Way Collars
|
|
Open Collars
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q4 2017
|
24
|
|
$
|
3.25
|
|
|
$
|
3.68
|
|
Total 2017
|
24
|
|
$
|
3.25
|
|
|
$
|
3.68
|
|
|
|
|
|
|
|
Q1 2018
|
11
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Q2 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Q3 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Q4 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Total 2018
|
47
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Natural Gas Net
Written Call Options
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q4 2017
|
12
|
|
$
|
9.43
|
|
Total 2017
|
12
|
|
$
|
9.43
|
|
|
|
|
|
Q1 2018
|
16
|
|
$
|
6.27
|
|
Q4 2018
|
16
|
|
$
|
6.27
|
|
Q3 2018
|
17
|
|
$
|
6.27
|
|
Q4 2018
|
17
|
|
$
|
6.27
|
|
Total 2018
|
66
|
|
$
|
6.27
|
|
|
|
|
|
Total 2019 –
2020
|
44
|
|
$
|
12.00
|
|
Natural Gas Basis
Protection Swaps
|
|
Volume
(bcf)
|
|
Avg. NYMEX
plus/(minus)
|
|
|
|
|
Q4 2017
|
17
|
|
$
|
(0.66)
|
|
Total 2017
|
17
|
|
$
|
(0.66)
|
|
|
|
|
|
Q1 2018
|
18
|
|
$
|
(0.78)
|
|
Q4 2018
|
18
|
|
$
|
(0.77)
|
|
Q3 2018
|
17
|
|
$
|
(0.77)
|
|
Q4 2018
|
6
|
|
$
|
(0.77)
|
|
Total 2018
|
59
|
|
$
|
(0.78)
|
|
The company's natural gas liquids hedging positions as of
October 31, 2017 were as follows:
Open Propane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price
of Open Swaps
|
|
|
|
|
Q4 2017
|
15
|
|
$
|
0.76
|
|
Total 2017
|
15
|
|
$
|
0.76
|
|
|
|
|
|
Q1 2018
|
3
|
|
$
|
0.73
|
|
Q4 2018
|
4
|
|
$
|
0.73
|
|
Q3 2018
|
4
|
|
$
|
0.73
|
|
Q4 2018
|
4
|
|
$
|
0.73
|
|
Total 2018
|
15
|
|
$
|
0.73
|
|
Open Butane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Open
Swaps
|
|
|
|
|
Q1 2018
|
1
|
|
$
|
0.88
|
|
Q4 2018
|
1
|
|
$
|
0.88
|
|
Q3 2018
|
1
|
|
$
|
0.88
|
|
Q4 2018
|
1
|
|
$
|
0.88
|
|
Total 2018
|
5
|
|
$
|
0.88
|
|
Open Butane Swaps
Priced as a Percentage of WTI
|
|
Volume (mmgal)
|
|
Avg. NYMEX as
a
% of WTI Open
Swaps
|
|
|
|
|
Q1 2018
|
1
|
|
70.5
|
%
|
Q4 2018
|
1
|
|
70.5
|
%
|
Q3 2018
|
1
|
|
70.5
|
%
|
Q4 2018
|
1
|
|
70.5
|
%
|
Total 2018
|
5
|
|
70.5
|
%
|
View original
content:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2017-third-quarter-financial-and-operational-results-300548219.html
SOURCE Chesapeake Energy Corp.