OKLAHOMA CITY, Feb. 27, 2019 /PRNewswire/ -- Chesapeake
Energy Corporation (NYSE: CHK) today reported financial and
operational results for the 2018 full year and fourth quarter.
Highlights include:
2018 Results:
- Portfolio evolution drives improved returns and leverage
reduction: Divested lower-margin Utica and
Mid-Continent assets and expanded higher-margin oil growth platform
through strategic focus on the Powder River Basin (PRB) and
announcement of the acquisition of WildHorse Resource Development
Corporation (WildHorse); overall total debt reduction of
$1.8 billion as of December 31, 2018, including the elimination of
$2.6 billion in secured debt;
- Oil production growth: 2018 average daily oil
production of approximately 90,000 barrels (bbls), up 10 percent
compared to 2017 levels, adjusted for asset sales; December 2018 oil production equaled 21 percent
of total production mix;
- Highest margins since 2014: 2018 net income
available to common stockholders of $775
million, or $0.85 per
diluted share; 2018 adjusted net income attributable to Chesapeake
of $816 million, or $0.90 per diluted share; 2018 fourth quarter net
income available to common stockholders of $486 million, or $0.49 per diluted share; 2018 fourth quarter
adjusted net income attributable to Chesapeake of $238 million, or $0.21 per diluted share; highest adjusted EBITDA
generated per barrel of oil equivalent (boe) of $12.81 since 2014.
2019 Outlook:
- Transformational oil growth: Projected 2019
average daily oil production of approximately 116,000 to 122,000
bbls, an absolute increase of approximately 32 percent (or 50
percent adjusted for asset sales), driven by the acquisition of the
WildHorse asset and organic growth from the PRB; oil mix projected
to be approximately 26 percent by 2019 fourth quarter;
- Capital expenditure program
discipline: Projected 2019 capital expenditures
range from $2.3 to $2.5 billion, effectively flat compared to
$2.366 billion in 2018;
- Lower costs lead to improved capital efficiency and
enhanced competitiveness: Cash costs projected to decrease
by approximately $200 million, driven
by lower gathering, processing and transportation (GP&T)
expenses partially offset by slightly higher production and general
and administrative expenses as a result of production and working
interest mix; EBITDA generated per boe projected to increase by
approximately 12 to 15 percent, based on recent strip prices.
Doug Lawler, Chesapeake's
President and Chief Executive Officer, commented, "I am very
pleased with Chesapeake's operational and financial performance in
2018. Two transformational business transactions not only serve as
a significant inflection point for the company, but also provide
foundational support in our strategic goals of further reducing our
net debt, achieving sustainable positive free cash flow, and
enhancing margins. The recent acquisition of WildHorse, which we
refer to as our Brazos Valley business unit, provides significant
profitability, flexibility and optionality to our diverse, deep
asset portfolio and facilitates our achieving these strategic
goals.
"Over the past five years, we have clearly established our
operational and capital efficiency leadership. We have also
materially improved our financial leverage and significantly
reduced our obligations, commitments and complexity. Our 2018
accomplishments of 10 percent adjusted oil growth, improved
realizations and lower absolute cash costs compared to 2017
resulted in the highest EBITDA generated per boe for Chesapeake
since 2014, when oil averaged more than $90 per barrel and gas averaged more than
$4 per thousand cubic feet. Our
strategic focus on increasing our oil production is working, as we
increased annual net oil volumes from the PRB by 78 percent in
2018, resulting in oil production representing 21 percent of our
overall production mix in December. Our oil focus will be fully
evident in 2019, as annual net oil volumes from the PRB are
expected to more than double compared to 2018 and as we begin a
robust drilling program on our Brazos Valley asset, while also
attacking the base production in all our operating areas with
full-field optimization and downtime reduction programs. As a
result, we project our average oil mix to be approximately 24
percent of total volumes in 2019 compared to 17 percent in 2018,
with our year-end 2019 oil mix approaching 26 percent.
"We are off to a fast start in 2019. With the integration of the
Brazos Valley asset into Chesapeake fully underway, we are already
seeing a significant amount of cost savings to be captured and
strong performance from the asset. The Brazos Valley asset had very
strong 2018 fourth quarter performance, with production, capital
expenditures and cash flow better than we had originally projected
at the time of the acquisition announcement.
"At today's strip pricing, we expect our cash flow to be
meaningfully stronger in 2019, as we continue to leverage our
strength in capital efficiency and cash cost leadership.
Chesapeake's progress, portfolio and strategic plan provides a
compelling investment opportunity and we look forward to driving
differential value for our shareholders in the year ahead."
2018 Full Year Results
For the 2018 full year, Chesapeake reported net income of
$877 million and net income available
to common stockholders of $775
million, or $0.85 per
diluted share, compared to $953
million, $813 million, and
$0.90 in 2017, respectively.
The company's EBITDA for the 2018 full year was $2.499 billion, compared to $2.376 billion in 2017. Adjusting for items that
are typically excluded by securities analysts, the 2018 full year
adjusted net income attributable to Chesapeake was $816 million, or $0.90 per diluted share, compared to $742 million, or $0.82 per diluted share in 2017, while the
company's adjusted EBITDA was $2.436
billion, compared to $2.160
billion in 2017. Reconciliations of financial measures
calculated in accordance with GAAP to non-GAAP measures are
provided on pages 14 - 17 of this release.
Average daily production for 2018 of approximately 521,000 boe
increased by 4 percent compared to 2017 levels, adjusted for asset
sales, and consisted of approximately 90,000 bbls of oil, 2.278
billion cubic feet (bcf) of natural gas and 52,000 bbls of NGL.
Production expenses in 2018 were $2.84 per boe, compared to $2.81 per boe in 2017. The per unit increase was
the result of increased ad valorem tax primarily due to higher
prices received for the company's oil, natural gas and NGL
production. General and administrative expenses (including
stock-based compensation) in 2018 were $1.47 per boe, compared to $1.31 per boe in 2017. The increase was primarily
due to less overhead allocated to production expenses, marketing
expenses and capitalized general and administrative costs, as well
as less overhead billed to working interest owners, due to certain
divestitures in 2018 and 2017.
2018 Fourth Quarter Results
For the 2018 fourth quarter, Chesapeake reported net income of
$514 million and net income available
to common stockholders of $486
million, or $0.49 per
diluted share, compared to $334
million, $309 million, and
$0.33 in the 2017 fourth quarter,
respectively. The company's EBITDA for the 2018 fourth quarter was
$910 million, compared to
$764 million in the 2017 fourth
quarter. Adjusting for items that are typically excluded by
securities analysts, the 2018 fourth quarter adjusted net income
attributable to Chesapeake was $238
million, or $0.21 per diluted
share, compared to $314 million, or
$0.30 per diluted share in the 2017
fourth quarter. The company's adjusted EBITDA was $574 million in the fourth quarter of 2018,
compared to $706 million in the
fourth quarter of 2017. Reconciliations of financial measures
calculated in accordance with GAAP to non-GAAP measures are
provided on pages 14 - 17 of this release.
Average daily production for the 2018 fourth quarter was
approximately 464,000 boe, a 7 percent decrease compared to 2017
levels, adjusted for asset sales, and consisted of approximately
87,000 bbls of oil, 2.009 bcf of natural gas and 42,000 bbls of
NGL.
Production expenses during the 2018 fourth quarter were
$2.87 per boe, compared to
$2.50 per boe in the 2017 fourth
quarter. The increase was primarily a result of certain 2018 and
2017 divestitures and increased ad valorem tax due to higher prices
received for the company's oil, natural gas and NGL production.
General and administrative expenses (including stock-based
compensation) during the 2018 fourth quarter were $1.19 per boe, compared to $1.34 per boe in the 2017 fourth quarter. The
decrease was primarily due to lower compensation expenses,
partially offset by less overhead allocated to production expenses,
marketing expenses and capitalized general and administrative
costs. The company's GP&T expenses increased to $7.92 per boe from $7.15 per boe during the 2017 fourth quarter,
primarily due to a shortfall payment for Eagle Ford oil
transportation volumes.
Capital Spending Overview
Chesapeake's total capital investments were approximately
$541 million during the 2018 fourth
quarter and $2.366 billion during the
2018 full year, compared to approximately $523 million and $2.458
billion in the 2017 fourth quarter and 2017 full year,
respectively. A summary of the company's 2018 and 2017 capital
expenditures, as well as the current 2019 capital expenditure
guidance, is provided in the table below.
|
2017
|
2018
|
2019
|
Operated activity
comparison
|
Q4
|
FY
|
Q4
|
FY
|
Outlook
|
Average rig
count
|
14
|
17
|
18
|
17
|
18 - 19
|
Gross wells
spud
|
66
|
341
|
82
|
322
|
350 - 360
|
Gross wells
completed
|
102
|
401
|
107
|
351
|
370 - 380
|
Gross wells
connected
|
118
|
411
|
119
|
347
|
365 - 375
|
|
|
|
|
|
|
Type of cost ($ in
millions)
|
|
|
|
|
|
Drilling and
completion costs
|
$
|
462
|
|
$
|
2,190
|
|
$
|
470
|
|
$
|
2,086
|
|
$2,050 -
$2,250
|
Exploration costs,
leasehold and additions to other PP&E
|
15
|
|
74
|
|
37
|
|
117
|
|
125
|
Subtotal capital
expenditures
|
$
|
477
|
|
$
|
2,264
|
|
$
|
507
|
|
$
|
2,203
|
|
$2,175 -
$2,375
|
Capitalized
interest
|
46
|
|
194
|
|
34
|
|
163
|
|
125
|
Total capital
expenditures
|
$
|
523
|
|
$
|
2,458
|
|
$
|
541
|
|
$
|
2,366
|
|
$2,300 -
$2,500
|
Balance Sheet and Hedge Position Update
As of December 31, 2018,
Chesapeake's principal amount of debt outstanding was approximately
$8.168 billion, compared to
$9.981 billion as of December 31, 2017, including $419 million drawn under its senior secured
revolving bank credit facility. As of December 31, 2018, Chesapeake had utilized
approximately $107 million for
various letters of credit and had borrowing capacity of
approximately $2.474 billion under
the $3.0 billion Chesapeake senior
secured revolving credit facility.
On February 1, 2019, Chesapeake
acquired approximately $1.4 billion
principal amount of debt upon the closing of the Brazos Valley
asset (including $675 million drawn
under the Brazos Valley senior secured revolving credit facility).
The company had approximately $47
million of letters of credit issued and borrowing capacity
of approximately $578 million under
the $1.3 billion Brazos Valley senior
secured revolving credit facility.
Chesapeake has a robust hedge portfolio in place for 2019 to
prudently reduce its future revenue risk. As of February 22, 2019, including January and February
derivative contracts that have settled, approximately 63 percent of
the company's 2019 forecasted oil, natural gas and NGL production
revenue was hedged, including approximately 56 percent and 81
percent of its 2019 forecasted oil and natural gas production
(including Brazos Valley production from February 1, 2019) at average prices of
$57.12 per bbl and $2.85 per thousand cubic feet (mcf),
respectively. Additionally, Chesapeake has basis protection on
approximately 7 million barrels (mmbbls) of its projected 2019
Eagle Ford oil production at a premium to WTI of approximately
$6.01 per bbl.
Operations Update
Chesapeake's average daily production for the 2018 full year was
approximately 521,000 boe compared to approximately 548,000 boe in
the 2017 full year. A summary of the company's 2018 average daily
production and average daily sales prices received by operating
divisions can be found in the company's Form 10-K.
Chesapeake's average daily production for the 2018 fourth
quarter was approximately 464,000 boe compared to approximately
593,000 boe in the 2017 fourth quarter. The following table shows
average daily production and average daily sales prices received by
the company's operating divisions for the 2018 fourth quarter and
the 2017 fourth quarter.
|
|
Three Months Ended
December 31, 2018
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
821
|
|
|
3.68
|
|
|
—
|
|
|
—
|
|
|
137
|
|
|
29
|
|
|
22.09
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
725
|
|
|
3.50
|
|
|
—
|
|
|
—
|
|
|
121
|
|
|
26
|
|
|
21.02
|
|
Eagle Ford
|
|
61
|
|
|
65.16
|
|
|
142
|
|
|
4.03
|
|
|
21
|
|
|
21.87
|
|
|
105
|
|
|
23
|
|
|
47.45
|
|
Mid-Continent
|
|
9
|
|
|
57.84
|
|
|
65
|
|
|
3.50
|
|
|
5
|
|
|
26.03
|
|
|
25
|
|
|
5
|
|
|
35.74
|
|
Powder River
Basin
|
|
14
|
|
|
56.01
|
|
|
78
|
|
|
3.86
|
|
|
4
|
|
|
23.82
|
|
|
31
|
|
|
7
|
|
|
37.94
|
|
Retained
assets
|
|
84
|
|
|
62.84
|
|
|
1,831
|
|
|
3.64
|
|
|
30
|
|
|
22.85
|
|
|
419
|
|
|
90
|
%
|
|
30.14
|
|
Divested
assets
|
|
3
|
|
|
67.45
|
|
|
178
|
|
|
3.12
|
|
|
12
|
|
|
30.44
|
|
|
45
|
|
|
10
|
|
|
24.92
|
|
Total
|
|
87
|
|
|
62.98
|
|
|
2,009
|
|
|
3.59
|
|
|
42
|
|
|
25.11
|
|
|
464
|
|
|
100
|
%
|
|
29.64
|
|
|
|
Three Months Ended
December 31, 2017
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
829
|
|
|
2.22
|
|
|
—
|
|
|
—
|
|
|
138
|
|
|
23
|
|
|
13.31
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
923
|
|
|
2.73
|
|
|
—
|
|
|
—
|
|
|
154
|
|
|
26
|
|
|
16.37
|
|
Eagle Ford
|
|
66
|
|
|
59.62
|
|
|
150
|
|
|
3.12
|
|
|
21
|
|
|
27.09
|
|
|
112
|
|
|
19
|
|
|
44.38
|
|
Mid-Continent
|
|
9
|
|
|
53.98
|
|
|
79
|
|
|
2.52
|
|
|
6
|
|
|
26.75
|
|
|
28
|
|
|
5
|
|
|
30.46
|
|
Powder River
Basin
|
|
7
|
|
|
54.35
|
|
|
45
|
|
|
2.90
|
|
|
3
|
|
|
33.30
|
|
|
18
|
|
|
3
|
|
|
34.82
|
|
Retained
assets
|
|
82
|
|
|
58.52
|
|
|
2,026
|
|
|
2.54
|
|
|
30
|
|
|
27.72
|
|
|
450
|
|
|
76
|
%
|
|
24.02
|
|
Divested
assets
|
|
18
|
|
|
52.25
|
|
|
577
|
|
|
2.66
|
|
|
30
|
|
|
29.36
|
|
|
143
|
|
|
24
|
%
|
|
23.16
|
|
Total
|
|
100
|
|
|
57.42
|
|
|
2,603
|
|
|
2.57
|
|
|
60
|
|
|
28.53
|
|
|
593
|
|
|
100
|
%
|
|
23.81
|
|
In the PRB, average daily net production increased approximately
70 percent in 2018 to 25,100 boe compared to 14,800 boe in 2017, as
total net annual production increased to 9.2 million barrels of oil
equivalent (mmboe) from 5.4 mmboe in 2017. Currently, the company
expects total net annual production from the PRB to double in 2019
compared to 2018.
Chesapeake is operating five rigs in the PRB, all of which are
currently drilling the Turner formation. Several records were
achieved in the PRB during the 2018 fourth quarter, including the
fastest per lateral foot drilling time in the Turner formation from
spud to total depth of 18.5 days for the BB 2-35-71 USA A TR 18H well with a drilled lateral
length of approximately 10,100 feet. Chesapeake also recorded its
highest producing oil well to date, including the SFU 7-34-71
USA A TR 20H well which was placed
on production in November 2018 and
recorded a 24-hour oil volume of 2,387 bbls (78 percent oil, or
3,068 boe).
In 2019, Chesapeake is moving to development mode in the Turner
formation, moving to central production facilities which will
handle up to 30,000 bbls of oil per day, consolidating drilling
activity to the more economic oil window located primarily in the
northern and western part of the play where there tends to be lower
gas-to-oil ratios. As a result, the company expects to double its
oil production from the PRB in 2019 by placing up to 64 Turner
wells on production, compared to 32 Turner wells in 2018 and its
first three wells drilled in the formation in 2017. While the
primary focus of the 2019 PRB program will be on the Turner
formation, the team will continue appraisal work on the
Niobrara and other horizons across
the basin.
Driven by the increase in oil volumes the company is projecting
going forward, Chesapeake signed an oil gathering agreement during
the 2018 fourth quarter that will deliver its oil volumes via
pipelines into the Guernsey,
Wyoming market at a substantially lower cost than the
company was incurring by trucking volumes. This oil gathering
system will also connect directly to interstate pipelines with
available capacity to the Cushing,
Oklahoma market and further to Gulf Coast premium markets,
providing additional takeaway options to Chesapeake in the future
as basin production grows.
In the company's legacy Eagle Ford Shale position in south
Texas, Chesapeake is currently
utilizing four drilling rigs and expects to place on production up
to 125 wells in 2019, compared to 157 wells in 2018. Of the wells
planned for 2019, Chesapeake expects to test up to 10 Upper Eagle
Ford and Austin Chalk wells. The company continues to focus on its
base production and has implemented new field technologies to
reduce downtime across the field. As a result, Chesapeake recorded
a 17 percent reduction in controllable down volumes per day in
2018, which equated to an additional 1,100 barrels of oil sold
every day. The company's significantly higher margins in the Eagle
Ford are primarily driven by premium Gulf Coast crude oil pricing
and are further protected with basis hedges on approximately 7
mmbbls of projected 2019 Eagle Ford oil production at a premium to
WTI of approximately $6.00 per
bbl.
The company's Brazos Valley business unit will be focused on
targeting both Eagle Ford and Austin Chalk wells in the large
acreage position gained in the WildHorse acquisition. Chesapeake
will operate four rigs in the Brazos Valley area in 2019 and
expects to place on production up to 83 wells, including 10 wells
targeting the Austin Chalk formation, with average completed
lateral lengths of approximately 8,000 feet. The business unit is
aggressively attacking numerous opportunities to drive capital
efficiencies across all areas of the value chain. Through a
combination of operational improvements and supply chain savings,
the team has implemented and negotiated approximately $200,000 to $350,000 per well in capital savings within the
first month of taking over operations. Early cycle time
improvements have been recognized through increased drilling
penetration rates and a two stage per day increase by the
completions team. Additionally, the Burleson Sand Mine commenced
operations in February 2019 and is
anticipated to yield additional savings to the company's
completions program.
In the Marcellus Shale in northeast Pennsylvania, Chesapeake is currently
utilizing three drilling rigs and expects to place on production up
to 48 wells in 2019, compared to 54 wells in 2018. Chesapeake
projects to again create significant free cash flow in 2019 as
stronger realized in-basin gas prices are expected to continue.
Current total gross production from the region is approximately 2.4
bcf per day, after reaching a record 2.5 bcf per day in
January 2019. In February 2019, Chesapeake placed two Upper
Marcellus wells on production in Susquehanna County that reached a combined
peak 24-hour rate of approximately 60 million cubic feet (mmcf) of
gas per day. Of the company's 48 wells expected to be placed on
production in 2019, seven wells will target the Upper Marcellus
formation.
In the company's Haynesville Shale position in Louisiana, Chesapeake is currently utilizing
two drilling rigs and intends to drop to one rig in the 2019 second
quarter. The company expects to place on production up to 24 wells
in 2019, compared to 26 wells in 2018.
In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing
one drilling rig and expects to place on production 25 wells in
2019, compared to 38 wells in 2018.
Key Financial and
Operational Results
|
|
The table below
summarizes Chesapeake's key financial and operational results
during the 2018 fourth quarter and full year as compared to results
in prior periods.
|
|
|
Three Months
Ended
December
31,
|
|
Years
Ended
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Barrels of oil
equivalent production (in mboe)
|
42,711
|
|
|
54,572
|
|
|
190,266
|
|
|
199,933
|
|
Barrels of oil
equivalent production (mboe/d)
|
464
|
|
|
593
|
|
|
521
|
|
|
548
|
|
Oil production (in
mbbl/d)
|
87
|
|
|
100
|
|
|
90
|
|
|
90
|
|
Average realized oil
price ($/bbl)(a)
|
56.86
|
|
|
56.47
|
|
|
57.42
|
|
|
53.19
|
|
Natural gas
production (in mmcf/d)
|
2,009
|
|
|
2,603
|
|
|
2,278
|
|
|
2,406
|
|
Average realized
natural gas price ($/mcf)(a)
|
3.19
|
|
|
2.76
|
|
|
3.00
|
|
|
2.75
|
|
NGL production (in
mbbl/d)
|
42
|
|
|
59
|
|
|
52
|
|
|
57
|
|
Average realized NGL
price ($/bbl)(a)
|
25.36
|
|
|
27.98
|
|
|
25.84
|
|
|
22.98
|
|
Production expenses
($/boe)
|
2.87
|
|
|
2.50
|
|
|
2.84
|
|
|
2.81
|
|
Gathering, processing
and transportation expenses ($/boe)
|
7.92
|
|
|
7.15
|
|
|
7.35
|
|
|
7.36
|
|
Oil -
($/bbl)
|
6.02
|
|
|
3.90
|
|
|
4.30
|
|
|
3.94
|
|
Natural Gas -
($/mcf)
|
1.41
|
|
|
1.30
|
|
|
1.32
|
|
|
1.34
|
|
NGL -
($/bbl)
|
7.40
|
|
|
7.83
|
|
|
8.37
|
|
|
7.88
|
|
Production taxes
($/boe)
|
0.77
|
|
|
0.45
|
|
|
0.65
|
|
|
0.44
|
|
General and
administrative expenses ($/boe)(b)
|
1.04
|
|
|
1.19
|
|
|
1.32
|
|
|
1.13
|
|
General and
administrative expenses (stock-based compensation) (non-cash)
($/boe)
|
0.15
|
|
|
0.15
|
|
|
0.15
|
|
|
0.18
|
|
Depreciation,
depletion and amortization ($/boe)
|
6.52
|
|
|
5.60
|
|
|
6.02
|
|
|
4.98
|
|
Interest expense
($/boe)(a)
|
2.78
|
|
|
2.25
|
|
|
2.55
|
|
|
2.11
|
|
Marketing net margin
($ in millions) (c)
|
(18)
|
|
|
1
|
|
|
(63)
|
|
|
(65)
|
|
Net cash provided by
operating activities
($
in millions)
|
405
|
|
|
472
|
|
|
2,000
|
|
|
745
|
|
Net cash provided by
operating activities($/boe)
|
9.47
|
|
|
8.65
|
|
|
10.51
|
|
|
3.73
|
|
Operating cash flow
($ in millions)(d)
|
367
|
|
|
577
|
|
|
1,846
|
|
|
1,216
|
|
Operating cash flow
($/boe)
|
8.59
|
|
|
10.57
|
|
|
9.70
|
|
|
6.09
|
|
Net income ($ in
millions)
|
514
|
|
|
334
|
|
|
877
|
|
|
953
|
|
Net income available
to common stockholders
($
in millions)
|
486
|
|
|
309
|
|
|
775
|
|
|
813
|
|
Net income per share
available to common stockholders – diluted
($)
|
0.49
|
|
|
0.33
|
|
|
0.85
|
|
|
0.90
|
|
Adjusted EBITDA ($ in
millions)(e)
|
574
|
|
|
706
|
|
|
2,436
|
|
|
2,160
|
|
Adjusted EBITDA
($/boe)
|
13.43
|
|
|
12.94
|
|
|
12.81
|
|
|
10.80
|
|
Adjusted net income
attributable to Chesapeake
($
in millions)(f)
|
238
|
|
|
314
|
|
|
816
|
|
|
742
|
|
Adjusted net income
attributable to Chesapeake
per
share - diluted ($ in millions)(g)
|
0.21
|
|
|
0.30
|
|
|
0.90
|
|
|
0.82
|
|
|
|
(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)
|
Excludes non-cash
amortization of $5 million for the three months ended December 31,
2018 and 2017, and $19 million and $22 million for the year ended
December 31, 2018 and 2017, respectively.
|
|
|
(d)
|
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 operating
activities on page 16.
|
|
|
(e)
|
Defined as net income
before interest expense, income taxes and depreciation, depletion
and amortization expense, as adjusted to remove the effects of
certain items detailed on page 17. This is a non-GAAP
measure. See reconciliation of net income to EBITDA on page
16 and reconciliation of EBITDA to adjusted EBITDA on page
17.
|
|
|
(f)
|
Defined as net income
attributable to Chesapeake, as adjusted to remove the effects of
certain items detailed on pages 14 - 15. This is a non-GAAP
measure. See reconciliation of net income to adjusted net income
available to Chesapeake on pages 14 - 15.
|
|
|
(g)
|
Our presentation of
diluted adjusted net income attributable to Chesapeake per share
excludes 1 million and 60 million shares for the three months ended
December 31, 2018 and 2017, respectively, and 207 million shares
for the years ended December 31, 2018 and 2017, considered
antidilutive when calculating diluted earnings per
share.
|
2018 Fourth Quarter and Year-End Results Conference Call
Information
A conference call to discuss this release has been scheduled on
Wednesday, February 27, 2019 at
9:00 am EST. The telephone number to
access the conference call is 334-323-0522 or toll-free
877-260-1479. The passcode for the call is 1327759. 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 1327759. 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
|
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
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
REVENUES:
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL
|
$
|
1,731
|
|
|
$
|
1,258
|
|
|
$
|
5,155
|
|
|
$
|
4,985
|
|
Marketing
|
1,338
|
|
|
1,261
|
|
|
5,076
|
|
|
4,511
|
|
Total
Revenues
|
3,069
|
|
|
2,519
|
|
|
10,231
|
|
|
9,496
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL production
|
122
|
|
|
136
|
|
|
539
|
|
|
562
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
338
|
|
|
390
|
|
|
1,398
|
|
|
1,471
|
|
Production
taxes
|
33
|
|
|
25
|
|
|
124
|
|
|
89
|
|
Marketing
|
1,360
|
|
|
1,265
|
|
|
5,158
|
|
|
4,598
|
|
General and
administrative
|
51
|
|
|
73
|
|
|
280
|
|
|
262
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
9
|
|
|
(73)
|
|
|
26
|
|
|
(38)
|
|
Depreciation,
depletion and amortization
|
278
|
|
|
306
|
|
|
1,145
|
|
|
995
|
|
Loss on sale of oil
and natural gas properties
|
578
|
|
|
—
|
|
|
578
|
|
|
—
|
|
Impairments
|
2
|
|
|
2
|
|
|
53
|
|
|
5
|
|
Other operating
(income) expense
|
4
|
|
|
(10)
|
|
|
10
|
|
|
413
|
|
Total Operating
Expenses
|
2,775
|
|
|
2,114
|
|
|
9,349
|
|
|
8,357
|
|
INCOME FROM
OPERATIONS
|
294
|
|
|
405
|
|
|
882
|
|
|
1,139
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
Interest
expense
|
(120)
|
|
|
(124)
|
|
|
(487)
|
|
|
(426)
|
|
Gains on
investments
|
—
|
|
|
—
|
|
|
139
|
|
|
—
|
|
Gains on purchases or
exchanges of debt
|
331
|
|
|
50
|
|
|
263
|
|
|
233
|
|
Other
income
|
7
|
|
|
3
|
|
|
70
|
|
|
9
|
|
Total Other Income
(Expense)
|
218
|
|
|
(71)
|
|
|
(15)
|
|
|
(184)
|
|
INCOME BEFORE
INCOME TAXES
|
512
|
|
|
334
|
|
|
867
|
|
|
955
|
|
INCOME TAX EXPENSE
(BENEFIT):
|
|
|
|
|
|
|
|
Current income
taxes
|
(2)
|
|
|
(11)
|
|
|
—
|
|
|
(9)
|
|
Deferred income
taxes
|
—
|
|
|
11
|
|
|
(10)
|
|
|
11
|
|
Total Income Tax
Expense (Benefit)
|
(2)
|
|
|
—
|
|
|
(10)
|
|
|
2
|
|
NET
INCOME
|
514
|
|
|
334
|
|
|
877
|
|
|
953
|
|
Net income
attributable to noncontrolling interests
|
(1)
|
|
|
(1)
|
|
|
(4)
|
|
|
(4)
|
|
NET INCOME
ATTRIBUTABLE TO CHESAPEAKE
|
513
|
|
|
333
|
|
|
873
|
|
|
949
|
|
Preferred stock
dividends
|
(23)
|
|
|
(23)
|
|
|
(92)
|
|
|
(85)
|
|
Loss on exchange of
preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(41)
|
|
Earnings allocated to
participating securities
|
(4)
|
|
|
(1)
|
|
|
(6)
|
|
|
(10)
|
|
NET INCOME
AVAILABLE TO COMMON STOCKHOLDERS
|
$
|
486
|
|
|
$
|
309
|
|
|
$
|
775
|
|
|
$
|
813
|
|
EARNINGS PER
COMMON SHARE:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.53
|
|
|
$
|
0.34
|
|
|
$
|
0.85
|
|
|
$
|
0.90
|
|
Diluted
|
$
|
0.49
|
|
|
$
|
0.33
|
|
|
$
|
0.85
|
|
|
$
|
0.90
|
|
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
|
|
|
Basic
|
910
|
|
|
907
|
|
|
909
|
|
|
906
|
|
Diluted
|
1,116
|
|
|
1,053
|
|
|
909
|
|
|
906
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
($ in
millions)
(unaudited)
|
|
December 31,
2018
|
|
December 31,
2017
|
|
|
|
|
Cash and cash
equivalents
|
$
|
4
|
|
|
$
|
5
|
|
Other current
assets
|
1,594
|
|
|
1,520
|
|
Total Current
Assets
|
1,598
|
|
|
1,525
|
|
|
|
|
|
Property and
equipment, net
|
9,030
|
|
|
10,680
|
|
Other long-term
assets
|
319
|
|
|
220
|
|
Total
Assets
|
$
|
10,947
|
|
|
$
|
12,425
|
|
|
Current
liabilities
|
$
|
2,828
|
|
|
$
|
2,356
|
|
Long-term debt,
net
|
7,341
|
|
|
9,921
|
|
Other long-term
liabilities
|
311
|
|
|
520
|
|
Total
Liabilities
|
10,480
|
|
|
12,797
|
|
|
|
|
|
Preferred
stock
|
1,671
|
|
|
1,671
|
|
Noncontrolling
interests
|
123
|
|
|
124
|
|
Common stock and
other stockholders' equity (deficit)
|
(1,327)
|
|
|
(2,167)
|
|
Total Equity
(Deficit)
|
467
|
|
|
(372)
|
|
Total Liabilities
and Equity
|
$
|
10,947
|
|
|
$
|
12,425
|
|
|
|
|
|
Common shares
outstanding (in millions)
|
914
|
|
|
909
|
|
Principal amount of
debt outstanding
|
$
|
8,168
|
|
|
$
|
9,981
|
|
CHESAPEAKE ENERGY
CORPORATION
SUPPLEMENTAL DATA
– OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST
EXPENSE
(unaudited)
|
|
Three Months
Ended
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net
Production:
|
|
|
|
|
|
|
|
Oil
(mmbbl)
|
8
|
|
|
9
|
|
|
33
|
|
|
33
|
|
Natural gas
(bcf)
|
185
|
|
|
239
|
|
|
832
|
|
|
878
|
|
NGL
(mmbbl)
|
4
|
|
|
5
|
|
|
19
|
|
|
21
|
|
Oil equivalent
(mmboe)
|
43
|
|
|
55
|
|
|
190
|
|
|
200
|
|
Average daily
production (mboe)
|
464
|
|
|
593
|
|
|
521
|
|
|
548
|
|
Oil, Natural Gas
and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
Oil sales
|
$
|
503
|
|
|
$
|
528
|
|
|
$
|
2,201
|
|
|
$
|
1,668
|
|
Natural gas
sales
|
664
|
|
|
615
|
|
|
2,486
|
|
|
2,422
|
|
NGL sales
|
98
|
|
|
156
|
|
|
502
|
|
|
484
|
|
Total oil, natural gas
and NGL sales
|
1,265
|
|
|
1,299
|
|
|
5,189
|
|
|
4,574
|
|
Financial
Derivatives:
|
|
|
|
|
|
|
|
Oil derivatives –
realized gains (losses)(a)
|
(48)
|
|
|
(9)
|
|
|
(321)
|
|
|
70
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
(76)
|
|
|
44
|
|
|
7
|
|
|
(9)
|
|
NGL derivatives –
realized gains (losses)(a)
|
1
|
|
|
(3)
|
|
|
(13)
|
|
|
(4)
|
|
Total realized gains
(losses) on financial derivatives
|
(123)
|
|
|
32
|
|
|
(327)
|
|
|
57
|
|
Oil derivatives –
unrealized gains (losses)(a)
|
560
|
|
|
(179)
|
|
|
445
|
|
|
(134)
|
|
Natural gas
derivatives – unrealized gains (losses)(a)
|
14
|
|
|
105
|
|
|
(154)
|
|
|
489
|
|
NGL derivatives –
unrealized gains (losses)(a)
|
15
|
|
|
1
|
|
|
2
|
|
|
(1)
|
|
Total unrealized
gains (losses) on financial derivatives
|
589
|
|
|
(73)
|
|
|
293
|
|
|
354
|
|
Total financial
derivatives
|
466
|
|
|
(41)
|
|
|
(34)
|
|
|
411
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,731
|
|
|
$
|
1,258
|
|
|
$
|
5,155
|
|
|
$
|
4,985
|
|
Average Sales
Price (excluding gains (losses) on derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
62.98
|
|
|
$
|
57.42
|
|
|
$
|
67.25
|
|
|
$
|
51.03
|
|
Natural gas ($ per
mcf)
|
$
|
3.59
|
|
|
$
|
2.57
|
|
|
$
|
2.99
|
|
|
$
|
2.76
|
|
NGL ($ per
bbl)
|
$
|
25.11
|
|
|
$
|
28.54
|
|
|
$
|
26.50
|
|
|
$
|
23.18
|
|
Oil equivalent ($ per
boe)
|
$
|
29.64
|
|
|
$
|
23.81
|
|
|
$
|
27.27
|
|
|
$
|
22.88
|
|
Average Sales
Price (excluding unrealized gains (losses) on
derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
56.86
|
|
|
$
|
56.47
|
|
|
$
|
57.42
|
|
|
$
|
53.19
|
|
Natural gas ($ per
mcf)
|
$
|
3.19
|
|
|
$
|
2.76
|
|
|
$
|
3.00
|
|
|
$
|
2.75
|
|
NGL ($ per
bbl)
|
$
|
25.36
|
|
|
$
|
27.98
|
|
|
$
|
25.84
|
|
|
$
|
22.98
|
|
Oil equivalent ($ per
boe)
|
$
|
26.75
|
|
|
$
|
24.41
|
|
|
$
|
25.56
|
|
|
$
|
23.17
|
|
Interest Expense
($ in millions):
|
|
|
|
|
|
|
|
Interest
expense(b)
|
$
|
121
|
|
|
$
|
123
|
|
|
$
|
488
|
|
|
$
|
425
|
|
Interest rate
derivatives – realized (gains) losses(c)
|
(1)
|
|
|
—
|
|
|
(3)
|
|
|
(3)
|
|
Interest rate
derivatives – unrealized (gains) losses(c)
|
—
|
|
|
1
|
|
|
2
|
|
|
4
|
|
Total interest
expense
|
$
|
120
|
|
|
$
|
124
|
|
|
$
|
487
|
|
|
$
|
426
|
|
|
|
(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 amounts reclassified
to realized (gains) losses during the period.
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
|
|
Three Months
Ended
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Beginning cash and
cash equivalents
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
882
|
|
|
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
405
|
|
|
472
|
|
|
2,000
|
|
|
745
|
|
|
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Drilling and
completion costs(a)
|
(477)
|
|
|
(589)
|
|
|
(1,958)
|
|
|
(2,186)
|
|
Acquisitions of
proved and unproved properties(b)
|
(44)
|
|
|
(59)
|
|
|
(288)
|
|
|
(285)
|
|
Proceeds from
divestitures of proved and unproved properties
|
1,836
|
|
|
56
|
|
|
2,231
|
|
|
1,249
|
|
Additions to other
property and equipment
|
(10)
|
|
|
(9)
|
|
|
(21)
|
|
|
(21)
|
|
Proceeds from sales
of other property and equipment
|
72
|
|
|
15
|
|
|
147
|
|
|
55
|
|
Proceeds from sales
of investments
|
—
|
|
|
—
|
|
|
74
|
|
|
—
|
|
Net cash provided
by (used in) investing activities
|
1,377
|
|
|
(586)
|
|
|
185
|
|
|
(1,188)
|
|
|
|
|
|
|
|
|
|
Net cash provided
by (used in) financing activities
|
(1,782)
|
|
|
114
|
|
|
(2,186)
|
|
|
(434)
|
|
Change in cash and
cash equivalents
|
—
|
|
|
—
|
|
|
(1)
|
|
|
(877)
|
|
Ending cash and
cash equivalents
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
5
|
|
|
|
(a)
|
Includes capitalized
interest of $2 million for the three months ended December 31,
2018 and 2017. Includes capitalized interest of $9 million for the
years ended December 31, 2018 and 2017.
|
|
|
(b)
|
Includes capitalized
interest of $32 million and $44 million for the three months ended
December 31, 2018 and 2017, respectively. Includes capitalized
interest of $153 million and $184 million for the years ended
December 31, 2018 and 2017, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME ATTRIBUTABLE TO
CHESAPEAKE
($ in millions except per share data)
(unaudited)
|
|
|
Three Months Ended
December 31,
|
|
|
2018
|
|
2017
|
|
|
$
|
|
$/Share(a)(b)
|
|
$
|
|
$/Share(a)(b)
|
Net income
available to common stockholders (GAAP)
|
|
$
|
486
|
|
|
$
|
0.53
|
|
|
$
|
309
|
|
|
$
|
0.34
|
|
Effect of dilutive
securities
|
|
59
|
|
|
|
|
35
|
|
|
|
Diluted earnings per
common stockholder (GAAP)
|
|
$
|
545
|
|
|
$
|
0.49
|
|
|
$
|
344
|
|
|
$
|
0.33
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
(596)
|
|
|
(0.53)
|
|
|
73
|
|
|
0.07
|
|
Provision for legal
contingencies, net
|
|
9
|
|
|
0.01
|
|
|
(73)
|
|
|
(0.07)
|
|
Loss on sale of oil
and natural gas properties (c)
|
|
578
|
|
|
0.52
|
|
|
—
|
|
|
—
|
|
Impairments
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Other operating
(income) expense
|
|
4
|
|
|
—
|
|
|
(10)
|
|
|
—
|
|
Gains on purchases or
exchanges of debt
|
|
(331)
|
|
|
(0.30)
|
|
|
(50)
|
|
|
(0.05)
|
|
Income tax expense
(benefit)(d)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
Adjusted net
income available to common stockholders(a) (b)
(Non-GAAP)
|
|
211
|
|
|
0.19
|
|
|
290
|
|
|
0.28
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
0.02
|
|
|
23
|
|
|
0.02
|
|
Earnings allocated to
participating securities
|
|
4
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Total adjusted net
income attributable to Chesapeake(a) (b)
(Non-GAAP)
|
|
$
|
238
|
|
|
$
|
0.21
|
|
|
$
|
314
|
|
|
$
|
0.30
|
|
|
|
(a)
|
Adjusted net income
available to common stockholders and total adjusted net income
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 available to common stockholders or earnings per
share. Adjusted net income available to common stockholders and
adjusted earnings 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 available to common stockholders to evaluate
the company's operational trends and performance relative to other
oil and natural gas producing companies.
|
|
|
|
|
(ii)
|
Adjusted net income
available to common stockholders is more comparable to earnings
estimates provided by securities analysts.
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items.
|
|
|
|
|
Because adjusted net
income available to common stockholders and total adjusted net
income attributable to Chesapeake exclude some, but not all, items
that affect net income available to common stockholders and total
adjusted net income attributable to Chesapeake may vary among
companies, our calculation of adjusted net income available to
common stockholders and total adjusted net income attributable to
Chesapeake may not be comparable to similarly titled financial
measures of other companies.
|
|
|
(b)
|
Our presentation of
diluted net income available to common stockholders and diluted
adjusted net income per share excludes 1 million and 60 million
shares considered antidilutive for the three months ended December
31, 2018 and 2017, respectively. The number of shares used for the
non-GAAP calculation were determined in a manner consistent with
GAAP.
|
|
|
(c)
|
Loss on sale of oil
and natural gas properties for the three months ended December 31,
2018 includes a $578 million loss related to the Utica
divestiture.
|
|
|
(d)
|
No income tax effect
from the adjustments has been included in determining adjusted net
income for the three months ended December 31, 2018 and 2017. Our
effective tax rate in both periods was 0% due to our valuation
allowance position.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME ATTRIBUTABLE TO
CHESAPEAKE
($ in millions except per share data)
(unaudited)
|
|
|
Years Ended
December 31,
|
|
|
2018
|
|
2017
|
|
|
$
|
|
$/Share(a)(b)
|
|
$
|
|
$/Share(a)(b)
|
Net income
available to common stockholders (GAAP)
|
|
$
|
775
|
|
|
$
|
0.85
|
|
|
$
|
813
|
|
|
0.90
|
|
Effect of dilutive
securities
|
|
—
|
|
|
|
|
—
|
|
|
|
Diluted earnings per
common stockholder (GAAP)
|
|
$
|
775
|
|
|
$
|
0.85
|
|
|
$
|
813
|
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized gains on
oil, natural gas and NGL derivatives
|
|
(300)
|
|
|
(0.33)
|
|
|
(354)
|
|
|
(0.39)
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
0.04
|
|
|
—
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
26
|
|
|
0.03
|
|
|
(38)
|
|
|
(0.04)
|
|
Loss on sale of oil
and natural gas properties (c)
|
|
578
|
|
|
0.64
|
|
|
—
|
|
|
—
|
|
Impairments
|
|
53
|
|
|
0.06
|
|
|
5
|
|
|
—
|
|
Other operating
expense
|
|
10
|
|
|
0.01
|
|
|
413
|
|
|
0.46
|
|
Gains on
investments
|
|
(139)
|
|
|
(0.15)
|
|
|
—
|
|
|
—
|
|
Gains on purchases or
exchanges of debt
|
|
(263)
|
|
|
(0.29)
|
|
|
(233)
|
|
|
(0.26)
|
|
Loss on exchange of
preferred stock
|
|
—
|
|
|
—
|
|
|
41
|
|
|
0.04
|
|
Income tax expense
(benefit)(d)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
(e)
|
|
(60)
|
|
|
(0.07)
|
|
|
—
|
|
|
—
|
|
Adjusted net
income available to common stockholders(a) (b)
(Non-GAAP)
|
|
718
|
|
|
0.79
|
|
|
647
|
|
|
0.71
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
92
|
|
|
0.10
|
|
|
85
|
|
|
0.10
|
|
Earnings allocated to
participating securities
|
|
6
|
|
|
0.01
|
|
|
10
|
|
|
0.01
|
|
Total adjusted net
income attributable to Chesapeake(a) (b)
(Non-GAAP)
|
|
$
|
816
|
|
|
$
|
0.90
|
|
|
$
|
742
|
|
|
$
|
0.82
|
|
|
|
(a)
|
Adjusted net income
available to common stockholders and total adjusted net income
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, or more meaningful
than, net income available to common stockholders or earnings per
share. Adjusted net income available to common stockholders and
adjusted earnings 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 available to common stockholders to evaluate
the company's operational trends and performance relative to other
oil and natural gas producing companies.
|
|
|
|
|
(ii)
|
Adjusted net income
available to common stockholders is more comparable to earnings
estimates provided by securities analysts.
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items.
|
|
|
|
|
Because adjusted net
income available to common stockholders and total adjusted net
income attributable to Chesapeake exclude some, but not all, items
that affect net income available to common stockholders and total
adjusted net income attributable to Chesapeake may vary among
companies, our calculation of adjusted net income available to
common stockholders and total adjusted net income attributable to
Chesapeake may not be comparable to similarly titled financial
measures of other companies.
|
|
|
(b)
|
Our presentation of
diluted net income available to common stockholders and diluted
adjusted net income attributable to Chesapeake per share excludes
207 million shares considered antidilutive for the years ended
December 31, 2018 and 2017. The number of shares used for the
non-GAAP calculation were determined in a manner consistent with
GAAP.
|
|
|
(c)
|
Loss on sale of oil
and natural gas properties for the year ended December 31, 2018
includes a $578 million loss related to the Utica
divestiture.
|
|
|
(d)
|
No income tax effect
from the adjustments has been included in determining adjusted net
income for the years ended December 31, 2018 and 2017. Our
effective tax rate in both periods was 0% due to our valuation
allowance position.
|
|
|
(e)
|
Other for the year
ended December 31, 2018 includes a $61 million gain related to an
extinguishment of the CHK Utica overriding royalty interest
conveyance obligation.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
|
|
Three Months
Ended
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
$
|
405
|
|
|
$
|
472
|
|
|
$
|
2,000
|
|
|
$
|
745
|
|
Changes in components
of working capital and other assets and liabilities
|
(38)
|
|
|
105
|
|
|
(154)
|
|
|
471
|
|
OPERATING CASH
FLOW (Non-GAAP)(a)
|
$
|
367
|
|
|
$
|
577
|
|
|
$
|
1,846
|
|
|
$
|
1,216
|
|
|
Three Months
Ended
December 31,
|
|
Years
Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
NET INCOME
(GAAP)
|
$
|
514
|
|
|
$
|
334
|
|
|
$
|
877
|
|
|
$
|
953
|
|
Interest
expense
|
120
|
|
|
124
|
|
|
487
|
|
|
426
|
|
Income tax expense
(benefit)
|
(2)
|
|
|
—
|
|
|
(10)
|
|
|
2
|
|
Depreciation,
depletion and amortization
|
278
|
|
|
306
|
|
|
1,145
|
|
|
995
|
|
EBITDA
(Non-GAAP)(b)
|
$
|
910
|
|
|
$
|
764
|
|
|
$
|
2,499
|
|
|
$
|
2,376
|
|
|
Three Months
Ended
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
$
|
405
|
|
|
$
|
472
|
|
|
$
|
2,000
|
|
|
$
|
745
|
|
Changes in assets and
liabilities
|
(38)
|
|
|
105
|
|
|
(154)
|
|
|
471
|
|
Interest
expense
|
120
|
|
|
124
|
|
|
487
|
|
|
426
|
|
Gains (losses) on
oil, natural gas and NGL derivatives, net
|
473
|
|
|
(41)
|
|
|
(26)
|
|
|
411
|
|
Cash (receipts)
payments on derivative settlements, net
|
183
|
|
|
(28)
|
|
|
345
|
|
|
18
|
|
Stock-based
compensation
|
(7)
|
|
|
(11)
|
|
|
(32)
|
|
|
(49)
|
|
Loss on sale of oil
and natural gas properties (c)
|
(578)
|
|
|
—
|
|
|
(578)
|
|
|
—
|
|
Impairments
|
(2)
|
|
|
(2)
|
|
|
(53)
|
|
|
(5)
|
|
Gains on
investments
|
—
|
|
|
—
|
|
|
139
|
|
|
—
|
|
Gains on purchases or
exchanges of debt
|
331
|
|
|
50
|
|
|
263
|
|
|
235
|
|
Other
items(d)
|
23
|
|
|
95
|
|
|
108
|
|
|
124
|
|
EBITDA
(Non-GAAP)(b)
|
$
|
910
|
|
|
$
|
764
|
|
|
$
|
2,499
|
|
|
$
|
2,376
|
|
|
|
(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 year ended
December 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.
|
|
|
(c)
|
Loss on sale of oil
and natural gas properties for the three months ended December 31,
2018 and the year ended December 31, 2018 includes a $578 million
loss related to the Utica divestiture.
|
|
|
(d)
|
Other items for the
year ended December 31, 2018 includes a $61 million gain related to
an extinguishment of the CHK Utica overriding royalty interest
conveyance obligation.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
|
|
Three Months
Ended
December 31,
|
|
Years Ended
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
EBITDA
(Non-GAAP)(a)
|
$
|
910
|
|
|
$
|
764
|
|
|
$
|
2,499
|
|
|
$
|
2,376
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Unrealized losses
(gains) on oil, natural gas and NGL derivatives
|
(596)
|
|
|
73
|
|
|
(300)
|
|
|
(354)
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
9
|
|
|
(73)
|
|
|
26
|
|
|
(38)
|
|
Loss on sale of oil
and natural gas properties (b)
|
578
|
|
|
—
|
|
|
578
|
|
|
—
|
|
Impairments
|
2
|
|
|
2
|
|
|
53
|
|
|
5
|
|
Other operating
(income) expense
|
4
|
|
|
(10)
|
|
|
10
|
|
|
413
|
|
Gains on
investments
|
—
|
|
|
—
|
|
|
(139)
|
|
|
—
|
|
Gains on purchases or
exchanges of debt
|
(331)
|
|
|
(50)
|
|
|
(263)
|
|
|
(233)
|
|
Net income
attributable to noncontrolling interests
|
(1)
|
|
|
(1)
|
|
|
(4)
|
|
|
(4)
|
|
Other
(c)
|
(1)
|
|
|
1
|
|
|
(62)
|
|
|
(5)
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
(Non-GAAP)(a)
|
$
|
574
|
|
|
$
|
706
|
|
|
$
|
2,436
|
|
|
$
|
2,160
|
|
|
|
(a)
|
EBITDA and Adjusted
EBITDA are not measures of financial performance under GAAP, and
should not be considered as an alternative to, or more meaningful
than, net income or cash flow provided by (used in) operations
prepared in accordance with GAAP. 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.
|
|
|
|
|
Because adjusted
EBITDA excludes some, but not all, items that affect net income,
our calculations of adjusted EBITDA may not be comparable to
similarly titled measures of other companies.
|
|
|
|
(b)
|
Loss on sale of oil
and natural gas properties for the three months ended December 31,
2018 and the year ended December 31, 2018 includes a $578 million
loss related to the Utica divestiture.
|
|
|
(c)
|
Other for the year
ended December 31, 2018 includes a $61 million gain related to an
extinguishment of the CHK Utica overriding royalty interest
conveyance obligation.
|
CHESAPEAKE ENERGY
CORPORATION
ROLL-FORWARD OF
PROVED RESERVES
YEAR ENDED
DECEMBER 31, 2018
(unaudited)
|
|
|
Mmboe(a)
|
|
|
|
Beginning balance,
December 31, 2017
|
|
1,912
|
|
Production
|
|
(190)
|
|
Extensions,
discoveries and other additions
|
|
270
|
|
Revisions of previous
estimates
|
|
15
|
|
Sale of reserves
in-place
|
|
(559)
|
|
Purchase of reserves
in-place
|
|
—
|
|
Ending balance,
December 31, 2018
|
|
1,448
|
|
|
|
|
Proved reserves
growth rate before acquisitions and divestitures
|
|
5
|
%
|
Proved reserves
growth rate after acquisitions and divestitures
|
|
(24)
|
%
|
|
|
|
Proved developed
reserves
|
|
748
|
|
Proved developed
reserves percentage
|
|
52
|
%
|
|
|
|
Standardized measure
of discounted future net cash flows ($ in millions)
(GAAP)
|
|
$
|
9,495
|
|
Add: Present value of
future income taxes discounted at 10% per
annum(a)
|
|
32
|
|
PV-10 ($ in
millions)(a) (Non-GAAP)
|
|
$
|
9,527
|
|
|
|
(a)
|
Reserve volumes and
PV-10 value estimated using SEC reserve recognition standards and
pricing assumptions based on the trailing 12-month average
first-day-of-the-month prices as of December 31, 2018 of $65.56 per
bbl of oil and $3.10 per mcf of natural gas, before basis
differential adjustments. 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 table
above shows the reconciliation of 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,
2018. Future income taxes in the calculation of the standardized
measure of discounted future net cash flows were $32 million as of
December 31, 2018.
|
CHESAPEAKE ENERGY
CORPORATION
|
MANAGEMENT'S
OUTLOOK AS OF FEBRUARY 27, 2019
|
|
Chesapeake
periodically provides guidance on certain factors that affect the
company's future financial performance.
|
|
|
Year
Ending
12/31/2019
|
|
|
Production Growth
Adjusted for Asset Sales(a)
|
13% to 20%
|
Absolute
Production:
|
|
Oil -
mmbbls
|
42.5 -
44.5
|
NGL -
mmbbls
|
13.0 -
15.0
|
Natural gas -
bcf
|
710 - 750
|
Total absolute
production - mmboe
|
174 - 184
|
Absolute daily rate -
mboe
|
475 - 505
|
Estimated Realized
Hedging Effects(b) (based on 2/22/19 strip
prices):
|
|
Oil -
$/bbl
|
($0.17)
|
Natural gas -
$/mcf
|
($0.07)
|
Estimated Basis to
NYMEX Prices:
|
|
Oil -
$/bbl
|
$1.20 -
$1.60
|
Natural gas -
$/mcf
|
($0.10) -
($0.20)
|
NGL - realizations as
a % of WTI
|
33% to 36%
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$3.25 -
$3.50
|
Gathering, processing
and transportation expenses
|
$6.00 -
$6.50
|
Oil -
$/bbl
|
$3.35 -
$3.55
|
Natural gas -
$/mcf
|
$1.20 -
$1.30
|
Production
taxes
|
$0.75 -
$0.85
|
General and
administrative(c)
|
$1.50 -
$1.60
|
Stock-based
compensation (non-cash)
|
$0.10 -
$0.20
|
DD&A of natural
gas and liquids assets
|
$5.50 -
$6.50
|
Depreciation of other
assets
|
$0.40 -
$0.50
|
Interest
expense
|
$3.20 -
$3.40
|
Marketing Net
Margin(d)
|
($25) -
($45)
|
Book Tax
Rate
|
0%
|
Adjusted EBITDA,
based on 2/22/19 strip prices ($ in
millions)(e)
|
$2,500 -
$2,700
|
Capital Expenditures
($ in millions)(f)
|
$2,175 -
$2,375
|
Capitalized Interest
($ in millions)
|
$125
|
Total Capital
Expenditures ($ in millions)
|
$2,300 -
$2,500
|
|
|
(a)
|
Based on 2018
production of 422 mboe per day, adjusted for asset
sales.
|
|
|
(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 Condensed
Consolidated Statement of Operations.
|
|
|
(d)
|
Excludes non-cash
amortization of approximately $8.7 million related to the buydown
of a transportation agreement.
|
|
|
(e)
|
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.
|
|
|
(f)
|
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 February 22, 2019, including
January and February derivative contracts that have settled,
approximately 63 percent of the company's 2019 forecasted oil,
natural gas and NGL production revenue was hedged, including
approximately 56 percent and 81 percent of its 2019 forecasted oil
and natural gas production (including Brazos Valley production from
February 1, 2019) at average prices
of $57.12 per bbl and $2.85 per mcf, respectively.
In addition, the company had downside protection on a portion of
its 2020 oil production at an average price of $59.72 per bbl and on a portion of its 2020 gas
production at an average price of $2.75 per mcf.
The company's crude oil hedging positions were as follows:
Open Crude Oil
Swaps
|
|
Open
Swaps
(mmbbls)
|
|
Avg.
NYMEX Price of
Swaps
|
|
|
|
|
Q1 2019
|
5
|
|
$
|
57.04
|
|
Q2 2019
|
5
|
|
$
|
57.09
|
|
Q3 2019
|
4
|
|
$
|
57.28
|
|
Q4 2019
|
3
|
|
$
|
57.33
|
|
Total 2019
|
17
|
|
$
|
57.16
|
|
|
|
|
|
Total 2020
|
7
|
|
$
|
58.28
|
|
Oil Two-Way
Collars
|
|
Collars
(mmbbls)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q1 2019
|
1
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q2 2019
|
1
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q3 2019
|
2
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q4 2019
|
2
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Total 2019
|
6
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
|
|
|
|
|
|
Total 2020
|
2
|
|
$
|
65.00
|
|
|
$
|
83.25
|
|
Oil
Puts
|
|
Volume
(mbbls)
|
|
Avg.
NYMEX
Bought Put
Price
|
|
|
|
|
Q1 2019
|
110
|
|
$
|
50.00
|
|
Q2 2019
|
221
|
|
$
|
52.63
|
|
Q3 2019
|
587
|
|
$
|
54.14
|
|
Q4 2019
|
832
|
|
$
|
54.43
|
|
Total 2019
|
1,750
|
|
$
|
53.83
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q1 2019
|
2
|
|
$
|
5.93
|
|
Q2 2019
|
3
|
|
$
|
5.93
|
|
Q3 2019
|
1
|
|
$
|
6.20
|
|
Q4 2019
|
1
|
|
$
|
6.20
|
|
Total 2019
|
7
|
|
$
|
6.01
|
|
The company's natural gas hedging positions were as follows:
Open Natural Gas
Swaps
|
|
Swaps
(bcf)
|
|
Avg.
NYMEX
Price of
Swaps
|
|
|
|
|
Q1 2019
|
109
|
|
$
|
2.98
|
|
Q2 2019
|
119
|
|
$
|
2.84
|
|
Q3 2019
|
115
|
|
$
|
2.84
|
|
Q4 2019
|
110
|
|
$
|
2.84
|
|
Total 2019
|
453
|
|
$
|
2.87
|
|
|
|
|
|
Total 2020
|
217
|
|
$
|
2.75
|
|
Natural Gas
Two-Way Collars
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q1 2019
|
27
|
|
$
|
2.75
|
|
|
$
|
3.13
|
|
Q2 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q3 2019
|
10
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q4 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Total 2019
|
55
|
|
$
|
2.75
|
|
|
$
|
3.02
|
|
Natural Gas
Three-Way Collars
|
|
Collars
(bcf)
|
|
Avg.
NYMEX
Sold Put Price
|
|
Avg.
NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
Q1 2019
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q2 2019
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q3 2019
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q4 2019
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Total 2019
|
88
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Natural Gas Net
Written Call Options
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q1 2019
|
5
|
|
$
|
12.00
|
|
Q2 2019
|
5
|
|
$
|
12.00
|
|
Q3 2019
|
6
|
|
$
|
12.00
|
|
Q4 2019
|
6
|
|
$
|
12.00
|
|
Total 2019
|
22
|
|
$
|
12.00
|
|
|
|
|
|
Total 2020
|
22
|
|
$
|
12.00
|
|
Natural Gas Net
Written Call Swaptions
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Total 2020
|
106
|
|
$
|
2.77
|
|
Natural Gas Basis
Protection Swaps
|
|
Volume
(bcf)
|
|
Avg. NYMEX
plus/(minus)
|
|
|
|
|
Q1 2019
|
12
|
|
$
|
(0.36)
|
|
Q2 2019
|
18
|
|
$
|
(0.84)
|
|
Q3 2019
|
14
|
|
$
|
(0.45)
|
|
Q4 2019
|
6
|
|
$
|
(0.39)
|
|
Total 2019
|
50
|
|
$
|
(0.56)
|
|
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multimedia:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2018-full-year-and-fourth-quarter-results-and-announces-2019-guidance-300802962.html
SOURCE Chesapeake Energy Corporation