OKLAHOMA CITY, May 8, 2019 /PRNewswire/ -- Chesapeake
Energy Corporation (NYSE:CHK) today reported financial and
operational results for the 2019 first quarter. Highlights
include:
- Early Brazos Valley (BVL) Success: Eliminated
approximately $500,000 in costs per
well since February 1, 2019, with
additional savings forecasted by year-end, driven by faster
drilling and more fracture stimulation stages completed per day;
have achieved savings of over $1
million per well on certain individual wells; early
production from first proprietary wells above expectations.
- On Track to Deliver Transformational Oil Growth in
2019: Driven by shallower production declines in
South Texas due to well spacing
and base production improvements and continued improvement in the
Powder River Basin (PRB), which achieved record production during
the quarter and again in the month of April
2019, the company remains on track to deliver oil growth of
approximately 32% with a year-end oil mix of approximately
26%.
- Average Oil Production of Approximately 109,000 Barrels
(Bbls) per Day: Year-over-year absolute growth of 18%, or
13% adjusted for asset purchases and sales, and approximately 22%
of total net daily production.
- Average Production of Approximately 484,000 Barrels of
Oil Equivalent (Boe) per Day
- Continued Shift to Higher Oil Mix and Focus on Reducing
Expenses Results in Highest Operating Margin per Boe Since
2014
Doug Lawler, Chesapeake's
President and Chief Executive Officer, commented, "We continue to
execute on our strategic priorities and once again delivered strong
financial and operational results. The encouraging early results
from our Brazos Valley business unit, which we now project will be
cash flow positive at the asset operating level in 2019,
demonstrates our capability to apply our capital and operating
efficiency to immediately transform a new asset in our portfolio.
We believe we will see significantly more savings in the year ahead
as we fully integrate our Brazos Valley operations into Chesapeake.
With our transformational oil growth and capital efficiency
continuing to improve, our confidence is strong as we drive towards
achieving our strategic priorities of meaningful margin
enhancement, sustainable free cash flow and a net debt to EBITDAX
ratio of two times."
2019 First Quarter Results
Average daily production for the 2019 first quarter was
approximately 484,000 boe and consisted of approximately 109,000
bbls of oil, 2.023 billion cubic feet (bcf) of natural gas and
39,000 bbls of natural gas liquids. Average daily production for
the 2018 first quarter was approximately 554,000 boe and consisted
of approximately 92,000 bbls of oil, 2.466 bcf of natural gas and
51,000 bbls of NGL. Oil production represented approximately 22% of
the company's 2019 first quarter aggregate production compared to
17% in the 2018 first quarter.
Chesapeake's operating margin per boe increased significantly in
the 2019 first quarter compared to the 2018 first quarter,
primarily driven by a higher oil production mix and a decrease in
certain of its cash operating expenses (production expenses,
gathering, processing and transportation expenses, and general and
administrative expenses). Chesapeake reduced its cash operating
expenses on an absolute basis by $81
million, or approximately $0.18 per boe, primarily driven by significant
reductions in the company's gathering, processing and
transportation expenses primarily as a result of certain 2018
divestitures.
In the 2019 first quarter, Chesapeake converted to the
successful efforts method of accounting for its oil and natural gas
exploration and development activities. See the table below for
successful efforts-based financial results and results as
calculated under the full cost method.
|
|
Three Months Ended
March 31, 2019
|
($ in millions,
except per share amounts)
|
|
As Reported
Under
Successful Efforts
|
|
Under Full
Cost
|
Net income (loss)
available to common stockholders
|
|
$
|
(44)
|
|
|
$
|
156
|
|
Net income (loss) per
diluted share
|
|
$
|
(0.03)
|
|
|
$
|
0.11
|
|
Adjusted net income
(loss) attributable to Chesapeake (non-GAAP)
|
|
$
|
(27)
|
|
|
$
|
197
|
|
Adjusted net income
(loss) per share attributable to Chesapeake (non-GAAP)
|
|
$
|
(0.02)
|
|
|
$
|
0.14
|
|
Adjusted EBITDAX
(non-GAAP)
|
|
$
|
676
|
|
|
$
|
688
|
|
Reconciliations of financial measures calculated in accordance
with GAAP to non-GAAP measures and pro forma comparisons to the
previously employed method of accounting are provided on pages
14-21 of this release.
Capital Spending Overview
Chesapeake incurred total capital expenditures of approximately
$559 million during the 2019 first
quarter, including capitalized interest of $6 million, compared to approximately
$543 million in the 2018 first
quarter. The increase in capital expenditures in the 2019 first
quarter was largely attributable to a higher average rig count and
an increase in gross wells spud, completed and connected. A summary
is provided in the table below.
|
|
Three Months
Ended
March 31,
|
|
|
2019
|
|
2018
|
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
Operated activity
comparison
|
|
|
|
|
|
|
|
|
Average rig
count
|
|
12
|
|
20
|
|
10
|
|
15
|
Wells spud
|
|
53
|
|
79
|
|
53
|
|
77
|
Wells
completed
|
|
60
|
|
83
|
|
56
|
|
76
|
Wells
connected
|
|
60
|
|
83
|
|
44
|
|
57
|
Three Months Ended
March 31, 2019
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Type of cost ($ in
millions)
|
|
|
|
|
|
|
Drilling and
completion capital expenditures
|
|
$
|
560
|
|
|
$
|
(18)
|
|
|
$
|
542
|
|
Leasehold and
additions to other PP&E
|
|
13
|
|
|
(2)
|
|
|
11
|
|
Subtotal capital
expenditures
|
|
$
|
573
|
|
|
$
|
(20)
|
|
|
$
|
553
|
|
Capitalized
interest
|
|
32
|
|
|
(26)
|
|
|
6
|
|
Total capital
expenditures
|
|
$
|
605
|
|
|
$
|
(46)
|
|
|
$
|
559
|
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Type of cost ($ in
millions)
|
|
|
|
|
|
|
Drilling and
completion capital expenditures
|
|
$
|
539
|
|
|
$
|
(17)
|
|
|
$
|
522
|
|
Leasehold and
additions to other PP&E
|
|
29
|
|
|
(12)
|
|
|
17
|
|
Subtotal capital
expenditures
|
|
$
|
568
|
|
|
$
|
(29)
|
|
|
$
|
539
|
|
Capitalized
interest
|
|
43
|
|
|
(39)
|
|
|
4
|
|
Total capital
expenditures
|
|
$
|
611
|
|
|
$
|
(68)
|
|
|
$
|
543
|
|
Balance Sheet and Liquidity
As of March 31, 2019, Chesapeake's
principal amount of debt outstanding inclusive of BVL debt was
approximately $9.978 billion,
compared to $8.168 billion as of
December 31, 2018. The increase in
debt outstanding was largely a result of $1.375 billion in debt assumed by Chesapeake as
part of the WildHorse acquisition on February 1, 2019. As of March 31, 2019, under the $3.0 billion Chesapeake credit facility, the
company had borrowed $842 million,
utilized approximately $61 million
for various letters of credit and had additional borrowing capacity
of approximately $2.097 billion.
Under the $1.3 billion BVL credit
facility, BVL had borrowed $688
million, utilized approximately $47
million for a letter of credit and had additional borrowing
capacity of approximately $565
million.
On April 3, 2019, Chesapeake
exchanged approximately $919 million
of new 8.0% Senior Notes due 2026 for approximately $884 million aggregate principal amount of its
Senior Notes due 2020 and 2021. On April 15,
2019, Chesapeake repaid at maturity approximately
$380 million of its Floating Rate
Senior Notes due 2019.
Chesapeake has a robust hedge portfolio in place for 2019 to
reduce its future revenue risk. As of May 3, 2019, including April and May derivative
contracts that have settled, approximately 70% of the company's
2019 forecasted oil, natural gas and NGL production revenue was
hedged, including approximately 70% and 80% of its remaining 2019
forecasted oil and natural gas production at average prices of
$58.75 per bbl and $2.83 per thousand cubic feet (mcf),
respectively. Additionally, Chesapeake has basis protection on
approximately 6 million barrels (mmbbls) of its remaining projected
2019 Eagle Ford oil production at a premium to WTI of approximately
$5.69 per bbl.
Operations Update
Chesapeake's average daily production for the 2019 first quarter
was approximately 484,000 boe compared to approximately 554,000 boe
in the 2018 first quarter. The following tables show average daily
production and average daily sales prices received (excluding
gains/losses on derivatives) by the company's operating areas for
the 2019 and 2018 first quarters.
|
|
Three Months Ended
March 31, 2019
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
948
|
|
|
3.54
|
|
|
—
|
|
|
—
|
|
|
158
|
|
|
33
|
|
|
21.23
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
759
|
|
|
2.94
|
|
|
—
|
|
|
—
|
|
|
126
|
|
|
26
|
|
|
17.63
|
|
Eagle Ford
|
|
62
|
|
|
59.77
|
|
|
149
|
|
|
3.58
|
|
|
24
|
|
|
21.69
|
|
|
110
|
|
|
23
|
|
|
42.97
|
|
Brazos
Valley(a)
|
|
23
|
|
|
59.32
|
|
|
23
|
|
|
2.04
|
|
|
3
|
|
|
8.25
|
|
|
30
|
|
|
6
|
|
|
47.55
|
|
Powder River
Basin
|
|
16
|
|
|
50.90
|
|
|
82
|
|
|
3.38
|
|
|
6
|
|
|
18.57
|
|
|
36
|
|
|
7
|
|
|
33.72
|
|
Mid-Continent
|
|
8
|
|
|
52.75
|
|
|
61
|
|
|
2.82
|
|
|
6
|
|
|
21.69
|
|
|
24
|
|
|
5
|
|
|
30.57
|
|
Retained
assets(b)
|
|
109
|
|
|
57.81
|
|
|
2,022
|
|
|
3.27
|
|
|
39
|
|
|
20.05
|
|
|
484
|
|
|
100
|
|
|
28.23
|
|
Divested
assets
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.82
|
|
Total
|
|
109
|
|
|
57.80
|
|
|
2,023
|
|
|
3.27
|
|
|
39
|
|
|
20.03
|
|
|
484
|
|
|
100
|
%
|
|
28.22
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
874
|
|
|
3.74
|
|
|
—
|
|
|
—
|
|
|
146
|
|
|
26
|
|
|
22.45
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
832
|
|
|
2.80
|
|
|
—
|
|
|
—
|
|
|
139
|
|
|
25
|
|
|
16.79
|
|
Eagle Ford
|
|
61
|
|
|
66.16
|
|
|
141
|
|
|
3.30
|
|
|
18
|
|
|
24.72
|
|
|
102
|
|
|
19
|
|
|
48.21
|
|
Powder River
Basin
|
|
7
|
|
|
62.87
|
|
|
47
|
|
|
2.82
|
|
|
3
|
|
|
28.77
|
|
|
18
|
|
|
3
|
|
|
37.66
|
|
Mid-Continent
|
|
8
|
|
|
61.92
|
|
|
62
|
|
|
2.68
|
|
|
4
|
|
|
26.06
|
|
|
23
|
|
|
4
|
|
|
34.74
|
|
Retained
assets(b)
|
|
76
|
|
|
65.36
|
|
|
1,956
|
|
|
3.25
|
|
|
25
|
|
|
25.38
|
|
|
428
|
|
|
77
|
|
|
28.07
|
|
Divested
assets
|
|
16
|
|
|
60.98
|
|
|
510
|
|
|
2.92
|
|
|
26
|
|
|
25.53
|
|
|
126
|
|
|
23
|
|
|
24.54
|
|
Total
|
|
92
|
|
|
64.61
|
|
|
2,466
|
|
|
3.18
|
|
|
51
|
|
|
25.45
|
|
|
554
|
|
|
100
|
%
|
|
27.27
|
|
|
|
(a)
|
Average production
per day since date of acquisition, 59 days, was approximately 35
mbbls of oil, 35 mmcf of natural gas and 5 mbbls of NGLs,
respectively, for an average total production of 45 mboe per
day.
|
|
|
(b)
|
Includes assets
retained as of March 31, 2019.
|
Brazos Valley
The company's new business unit, which operates in the northern
part of the Eagle Ford Shale and Austin
Chalk Trend located primarily in Burleson, Lee
and Washington counties in
Texas, has already seen significant operational improvements
since the company's acquisition closed on February 1, 2019. Within the first two months of
owning the asset, Chesapeake has dramatically improved cycle times
with faster drilling and more fracture stimulation stages completed
per day, resulting in significant cost reductions. Through the
first two months of operations, the company has already realized
savings of approximately $500,000 per
well due to improved drilling and completion techniques, supply
chain and logistics synergies and the switch to regional sand
sourced from its wholly owned sand mine in Burleson County that commenced operations in
February 2019. Additional cost
savings have been identified and the company expects the per-well
savings to increase throughout the year.
On the company's Eagle Ford Easy Rider pad located in
Burleson County, Chesapeake
initiated its first choke management test in the area yielding
significantly improved results. With completed laterals of
approximately 7,500 feet, the pad's two wells achieved 24-hour peak
oil production rates of 898 bbls per day and 1,546 bbls per day,
respectively, demonstrating an approximate 35% uplift to historical
type curve estimates from the area.
Additionally, Chesapeake has drilled and completed its first set
of proprietary Eagle Ford wells on the Bell pad located in Burleson County. These four wells were
completed with decreased fluid volumes (8,000 bbls per stage
compared to 10,000 to 12,000 bbls per stage previously) and were
placed on production in April 2019.
While the average production rate from the pad is still climbing,
the pad has already achieved a peak 24-hour oil production rate of
2,723 bbls of oil. These results are encouraging as the company
optimizes fracture stimulations with lower fluids and higher sand
volumes, simultaneously reducing costs and increasing
productivity.
The company is currently utilizing four rigs in the area, placed
13 wells on production (five gas wells and eight oil wells) during
the 2019 first quarter and expects to place 27 wells on production
(four gas wells and 23 oil wells) during the 2019 second quarter.
Included in the company's first quarter capital program were wells
in the process of being completed in the gas window of the Austin
Chalk play at the time of the closing of the acquisition. The
company has since moved all four rigs to the oil and volatile oil
windows of the Eagle Ford due to better economics and oil volumes.
Chesapeake now anticipates its 2019 drilling program will average a
lateral length of approximately 9,000 feet per well, representing a
27% increase over 2018 levels. The combination of longer laterals,
optimized completions and effective flow back procedures have
already delivered significant improvements in capital efficiency
and returns, as expected as part of the company's original
acquisition analysis, with more improvements expected in the next
few months.
Eagle Ford Shale
In the company's Eagle Ford Shale position in South Texas, Chesapeake continues to generate
free cash flow through steady oil volume production. Well
performance has been especially strong due to optimized well
spacing, enhanced completion designs and base production
improvements resulting in consistent, high-margin oil volumes and
markedly shallower production declines. Additional base production
management efforts are expected throughout the year. Chesapeake is
currently utilizing four rigs in South
Texas, placed 29 wells on production during the 2019 first
quarter and expects to place 16 wells on production during the 2019
second quarter.
The company is able to access Gulf Coast premium markets
resulting in higher realized crude oil pricing for both its Brazos
Valley and legacy Eagle Ford areas, contributing to higher margins.
The company has protected a portion of this pricing advantage with
basis hedges on approximately 6 mmbbls of remaining projected 2019
oil production at a premium to WTI of approximately $5.69 per bbl.
Powder River Basin
As a part of its ongoing portfolio optimization, Chesapeake has
recently shifted a portion of its planned capital dollars from its
Marcellus Shale and Mid-Continent areas to the PRB, where the
company has recently moved a sixth rig. While all six rigs are
currently drilling in the Turner formation, the company will
transition one of the rigs to selectively drill Niobrara wells
later in the year.
Average net production from the PRB for the 2019 first quarter
was approximately 36,000 boe per day, including 16,000 bbls of oil,
after experiencing several significant downtime events due to
winter weather. Average net production from the PRB for the month
of April was approximately 39,000 boe per day, including 18,000
bbls of oil and, as of May 1, 2019,
the company set a new production record of approximately 42,000 boe
per day, including 20,000 bbls of oil. The company placed 13 wells
on production during the 2019 first quarter and expects to place 15
wells on production during the 2019 second quarter. As a result of
the additional capital allocated to the PRB, the company now
expects to place an additional eight wells to sales during the 2019
third and fourth quarters than initially forecasted.
Chesapeake recently achieved a new record-setting Turner oil
well, the RRC 5-34-70 USA B TR
21H, which reached a peak rate of approximately 4,000 boe per day
(75% oil) on May 4, 2019, while
flowing at 2,000 psi wellhead pressure on a 48/64 inch choke. The
company is encouraged by the exceptional well results in this area
and expects continued success in the 2019 development program.
In May 2019, Chesapeake began
connecting pads into a new oil gathering pipeline system which will
transport volumes to Guernsey,
Wyoming. The company expects the system to be fully
operational across the field by June
2019, resulting in significant cost savings and improved
certainty of delivery compared to trucking volumes. Chesapeake will
use this new gathering system as an entry point into interstate
pipelines and is working to deliver these volumes both to
Cushing, Oklahoma beginning this
summer and to Gulf Coast premium markets at Corpus Christi beginning in late 2020.
Marcellus Shale
Chesapeake continues to generate significant free cash flow in
the Marcellus Shale in northeast Pennsylvania, primarily driven by strong
realized in-basin gas prices and record production from improved
well productivity through enhanced completions and longer laterals.
Chesapeake achieved a record daily gross production level of
approximately 2.5 bcf of gas per day in January 2019, resulting in record average net
production of 948 mcf of gas per day during the 2019 first quarter.
The company is currently utilizing three rigs but plans to move to
two rigs by the end of June 2019.
Chesapeake placed nine wells on production during the 2019 first
quarter and expects to place 14 wells on production during the 2019
second quarter.
Haynesville Shale
In the Haynesville Shale in Louisiana, Chesapeake expects to decrease its
activity throughout the year, moving from two rigs to one rig by
the end of May 2019. The company
placed ten wells on production in the Haynesville Shale during the
2019 first quarter and expects to place nine wells on production
during the 2019 second quarter.
Mid-Continent
In the company's Mid-Continent operating area in Oklahoma, Chesapeake dropped its only rig in
May 2019. The company placed nine
wells on production during the 2019 first quarter and expects to
place five wells on production during the 2019 second quarter. The
company expects to increase activity in the Mid-Continent area in
2020, after newly acquired 3D seismic has been interpreted and its
drilling inventory has been high-graded.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and
operational results during the 2019 first quarter as compared to
results in prior periods. The three months ended March 31, 2019 include two months of Brazos
Valley operations. The three months ending March 31, 2018 do not include Brazos Valley
operations.
|
|
Three Months
Ended
March 31,
|
|
|
2019
|
|
2018
|
Barrels of oil
equivalent production (in mboe)
|
|
43,600
|
|
|
49,879
|
|
Barrels of oil
equivalent production (mboe/d)
|
|
484
|
|
|
554
|
|
Oil production (in
mbbl/d)
|
|
109
|
|
|
92
|
|
Average realized oil
price ($/bbl)(a)
|
|
56.86
|
|
|
56.89
|
|
Natural gas
production (in mmcf/d)
|
|
2,023
|
|
|
2,466
|
|
Average realized
natural gas price ($/mcf)(a)
|
|
3.07
|
|
|
3.49
|
|
NGL production (in
mbbl/d)
|
|
39
|
|
|
51
|
|
Average realized NGL
price ($/bbl)(a)
|
|
20.03
|
|
|
25.36
|
|
Production expenses
($/boe)
|
|
3.02
|
|
|
2.94
|
|
Gathering, processing
and transportation expenses ($/boe)
|
|
6.29
|
|
|
7.15
|
|
Oil -
($/bbl)
|
|
3.47
|
|
|
4.18
|
|
Natural Gas -
($/mcf)
|
|
1.21
|
|
|
1.27
|
|
NGL -
($/bbl)
|
|
5.57
|
|
|
8.83
|
|
Production taxes
($/boe)
|
|
0.78
|
|
|
0.62
|
|
Exploration expenses
($ in millions)
|
|
24
|
|
|
81
|
|
General and
administrative expenses ($/boe)(b)
|
|
2.20
|
|
|
1.60
|
|
General and
administrative expenses (stock-based compensation) (non-cash)
($/boe)
|
|
0.14
|
|
|
0.14
|
|
DD&A of oil and
natural gas properties ($/boe)
|
|
11.90
|
|
|
9.20
|
|
Interest expense
($/boe)(c)
|
|
3.67
|
|
|
3.25
|
|
Marketing net margin
($ in millions)(d)
|
|
8
|
|
|
(17)
|
|
Net cash provided by
operating activities ($ in millions)
|
|
456
|
|
|
588
|
|
Net cash provided by
operating activities ($/boe)
|
|
10.46
|
|
|
11.79
|
|
Net income (loss) ($
in millions)
|
|
(21)
|
|
|
18
|
|
Net loss available to
common stockholders ($ in millions)
|
|
(44)
|
|
|
(6)
|
|
Net loss per share
available to common stockholders – diluted ($)
|
|
(0.03)
|
|
|
(0.01)
|
|
Adjusted EBITDAX ($
in millions)(e)
|
|
676
|
|
|
717
|
|
Adjusted EBITDAX
($/boe)
|
|
15.50
|
|
|
14.37
|
|
Adjusted net income
(loss) attributable to Chesapeake ($ in
millions)(f)
|
|
(27)
|
|
|
16
|
|
Adjusted net income
(loss) attributable to Chesapeake per share - diluted ($)(g)
|
|
(0.02)
|
|
|
0.02
|
|
|
|
(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)
|
Includes the effects
of realized (gains) losses from interest rate derivatives, excludes
the effects of unrealized (gains) losses from interest rate
derivatives and is shown net of amounts capitalized.
|
(d)
|
Excludes non-cash
amortization of $5 million for the three months ended March 31,
2019 and 2018, related to the buydown of a transportation
agreement.
|
(e)
|
Defined as net income
(loss) before interest expense, income taxes, depreciation,
depletion and amortization expense, and exploration expense, as
adjusted to remove the effects of certain items detailed on page
20. This is a non-GAAP measure. See reconciliation of cash provided
by operating activities to adjusted EBITDAX on page 19 and
reconciliation of net income (loss) to adjusted EBITDAX on page
20.
|
(f)
|
Defined as net income
(loss) attributable to Chesapeake, as adjusted to remove the
effects of certain items detailed on pages 14-18. This is a
non-GAAP measure. See reconciliation of net income (loss) to
adjusted net income (loss) available to Chesapeake on pages
14-18.
|
(g)
|
Our presentation of
diluted adjusted net income (loss) attributable to Chesapeake per
share excludes 206 million shares for the three months ended March
31, 2019 and 2018, which are considered antidilutive when
calculating diluted earnings per share.
|
2019 First Quarter Financial and Operational Results
Conference Call Update
The conference call to discuss the company's financial and
operational results has been scheduled on Wednesday, May 8 at 9:00
am EDT. The telephone number to access the conference call
is 877-870-4263 or 1-412-317-0790 for international callers. The
passcode for the call is 4269013. The conference call will be
webcast and can be found at www.chk.com in the "Investors"
section of the company's website.
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, expected lateral lengths of wells,
anticipated timing of wells to be placed into production,
anticipated timing of the Brazos Valley business unit becoming cash
flow positive, general and administrative expenses, capital
expenditures, projected cash flow and
liquidity, our ability to enhance our cash flow
and financial flexibility, plans and objectives for future
operations, the ability of our employees, portfolio strength and
operational leadership to create long-term value, and the
assumptions on which such statements are based. Although we believe
the expectations and forecasts reflected in the forward-looking
statements are reasonable, we can give no assurance they will prove
to have been correct. They can be affected by inaccurate or changed
assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially
from expected results include those described under "Risk Factors"
in Item 1A of our annual report on Form 10-K and any updates to
those factors set forth in Chesapeake's subsequent quarterly
reports on Form 10-Q or current reports on Form 8-K (available at
http://www.chk.com/investors/sec-filings). These risk factors
include the volatility of oil, natural gas and NGL prices; the
limitations our level of indebtedness may have on our financial
flexibility; our inability to access the capital markets on
favorable terms; the availability of cash flows from operations and
other funds to finance reserve replacement costs or satisfy our
debt obligations; downgrade in our credit rating requiring us to
post more collateral under certain commercial arrangements;
write-downs of our oil and natural gas asset carrying values due to
low commodity prices; our ability to replace reserves and sustain
production; uncertainties inherent in estimating quantities of oil,
natural gas and NGL reserves and projecting future rates of
production and the amount and timing of development expenditures;
our ability to generate profits or achieve targeted results in
drilling and well operations; leasehold terms expiring before
production can be established; commodity derivative activities
resulting in lower prices realized on oil, natural gas and NGL
sales; the need to secure derivative liabilities and the inability
of counterparties to satisfy their obligations; adverse
developments or losses from pending or future litigation and
regulatory proceedings, including royalty claims; charges incurred
in response to market conditions and in connection with our ongoing
actions to reduce financial leverage and complexity; drilling and
operating risks and resulting liabilities; effects of environmental
protection laws and regulation on our business; legislative and
regulatory initiatives further regulating hydraulic fracturing; our
need to secure adequate supplies of water for our drilling
operations and to dispose of or recycle the water used; impacts of
potential legislative and regulatory actions addressing climate
change; federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge
against commodity price fluctuations; competition in the oil and
gas exploration and production industry; a deterioration in general
economic, business or industry conditions; negative public
perceptions of our industry; limited control over properties we do
not operate; pipeline and gathering system capacity constraints and
transportation interruptions; terrorist activities and
cyber-attacks adversely impacting our operations; an interruption
in operations at our headquarters due to a catastrophic event;
certain anti-takeover provisions that affect shareholder rights;
and our inability to increase or maintain our liquidity through
debt repurchases, capital exchanges, asset sales, joint ventures,
farmouts or other means.
In addition, disclosures concerning the estimated
contribution of derivative contracts to our future results of
operations are based upon market information as of a specific date.
These market prices are subject to significant volatility. Our
production forecasts are also dependent upon many assumptions,
including estimates of production decline rates from existing wells
and the outcome of future drilling activity. Expected asset sales
may not be completed in the time frame anticipated or at all. We
caution you not to place undue reliance on our forward-looking
statements, which speak only as of the date of this news release,
and we undertake no obligation to update any of the information
provided in this release or the accompanying Outlook, except as
required by applicable law. In addition, this news release contains
time-sensitive information that reflects management's best judgment
only as of the date of this news release.
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
(405)
935-8870
ir@chk.com
|
Gordon
Pennoyer
(405)
935-8878
media@chk.com
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions
except per share data)
(unaudited)
|
|
|
Three Months
Ended
March 31,
|
|
|
2019
|
|
2018*
|
REVENUES AND
OTHER:
|
|
|
|
|
Oil, natural gas and
NGL(a)
|
|
$
|
929
|
|
|
$
|
1,243
|
|
Marketing
|
|
1,233
|
|
|
1,246
|
|
Total Revenues
|
|
2,162
|
|
|
2,489
|
|
Other
|
|
15
|
|
|
16
|
|
Gains on sales of
assets
|
|
19
|
|
|
19
|
|
Total Revenues and
Other
|
|
2,196
|
|
|
2,524
|
|
OPERATING
EXPENSES:
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
132
|
|
|
147
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
|
274
|
|
|
356
|
|
Production
taxes
|
|
34
|
|
|
31
|
|
Exploration
|
|
24
|
|
|
81
|
|
Marketing
|
|
1,230
|
|
|
1,268
|
|
General and
administrative
|
|
103
|
|
|
87
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
|
—
|
|
|
5
|
|
Depreciation,
depletion and amortization
|
|
519
|
|
|
459
|
|
Impairments
|
|
1
|
|
|
10
|
|
Other operating
expense
|
|
61
|
|
|
—
|
|
Total Operating
Expenses
|
|
2,378
|
|
|
2,482
|
|
INCOME (LOSS) FROM
OPERATIONS
|
|
(182)
|
|
|
42
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
Interest
expense
|
|
(161)
|
|
|
(162)
|
|
Gains (losses) on
investments
|
|
(1)
|
|
|
139
|
|
Other income
(expense)
|
|
9
|
|
|
(1)
|
|
Total Other
Expense
|
|
(153)
|
|
|
(24)
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
|
(335)
|
|
|
18
|
|
Income tax
benefit
|
|
(314)
|
|
|
—
|
|
NET INCOME
(LOSS)
|
|
(21)
|
|
|
18
|
|
Net income
attributable to noncontrolling interests
|
|
—
|
|
|
(1)
|
|
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
|
|
(21)
|
|
|
17
|
|
Preferred stock
dividends
|
|
(23)
|
|
|
(23)
|
|
NET LOSS AVAILABLE
TO COMMON STOCKHOLDERS
|
|
$
|
(44)
|
|
|
$
|
(6)
|
|
EARNINGS (LOSS)
PER COMMON SHARE:
|
|
|
|
|
Basic
|
|
$
|
(0.03)
|
|
|
$
|
(0.01)
|
|
Diluted
|
|
$
|
(0.03)
|
|
|
$
|
(0.01)
|
|
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
Basic
|
|
1,380
|
|
|
907
|
|
Diluted
|
|
1,380
|
|
|
907
|
|
|
* Financial
information for 2018 has been recast to reflect the retrospective
application of the successful efforts method of
accounting.
|
|
|
(a)
|
See page 12 for a
reconciliation of oil, natural gas and NGL revenue before and after
the effect of financial derivatives.
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
($ in
millions)
(unaudited)
|
|
|
March 31,
2019
|
|
December 31,
2018
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
8
|
|
|
$
|
4
|
|
Other current
assets
|
|
1,357
|
|
|
1,594
|
|
Total Current
Assets
|
|
1,365
|
|
|
1,598
|
|
|
|
|
|
|
Property and
equipment, net
|
|
14,939
|
|
|
10,818
|
|
Other long-term
assets
|
|
333
|
|
|
319
|
|
Total
Assets
|
|
$
|
16,637
|
|
|
$
|
12,735
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
2,930
|
|
|
$
|
2,887
|
|
Long-term debt,
net
|
|
9,167
|
|
|
7,341
|
|
Other long-term
liabilities
|
|
402
|
|
|
374
|
|
Total
Liabilities
|
|
12,499
|
|
|
10,602
|
|
|
|
|
|
|
Preferred
stock
|
|
1,671
|
|
|
1,671
|
|
Noncontrolling
interests
|
|
41
|
|
|
41
|
|
Common stock and
other stockholders' equity
|
|
2,426
|
|
|
421
|
|
Total
Equity
|
|
4,138
|
|
|
2,133
|
|
|
|
|
|
|
Total Liabilities
and Equity
|
|
$
|
16,637
|
|
|
$
|
12,735
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
SUPPLEMENTAL DATA
– OIL, NATURAL GAS AND NGL PRODUCTION AND SALES
PRICES
(unaudited)
|
|
Three Months
Ended
March 31,
|
|
2019
|
|
2018
|
Net
Production:
|
|
|
|
Oil
(mmbbl)
|
10
|
|
|
8
|
|
Natural gas
(bcf)
|
182
|
|
|
222
|
|
NGL
(mmbbl)
|
4
|
|
|
5
|
|
Oil equivalent
(mmboe)
|
44
|
|
|
50
|
|
Average daily
production (mboe)
|
484
|
|
|
554
|
|
Oil, Natural Gas
and NGL Sales ($ in millions):
|
|
|
|
Oil sales
|
$
|
566
|
|
|
$
|
537
|
|
Natural gas
sales
|
595
|
|
|
706
|
|
NGL sales
|
69
|
|
|
117
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,230
|
|
|
$
|
1,360
|
|
|
|
|
|
Financial
Derivatives:
|
|
|
|
Oil derivatives –
realized gains (losses)(a)
|
$
|
10
|
|
|
(64)
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
(36)
|
|
|
67
|
|
NGL derivatives –
realized losses(a)
|
—
|
|
|
(1)
|
|
Total realized gains
(losses) on financial derivatives
|
$
|
(26)
|
|
|
$
|
2
|
|
|
|
|
|
Oil derivatives –
unrealized losses(b)
|
(269)
|
|
|
(22)
|
|
Natural gas
derivatives – unrealized losses(b)
|
(6)
|
|
|
(99)
|
|
NGL derivatives –
unrealized gains(b)
|
—
|
|
|
2
|
|
Total unrealized
losses on financial derivatives
|
$
|
(275)
|
|
|
$
|
(119)
|
|
|
|
|
|
Total financial
derivatives
|
$
|
(301)
|
|
|
$
|
(117)
|
|
|
|
|
|
Total oil, natural
gas and NGL sales
|
$
|
929
|
|
|
$
|
1,243
|
|
Average Sales
Price (excluding gains (losses) on derivatives):
|
|
|
|
Oil ($ per
bbl)
|
$
|
57.80
|
|
|
$
|
64.61
|
|
Natural gas ($ per
mcf)
|
$
|
3.27
|
|
|
$
|
3.18
|
|
NGL ($ per
bbl)
|
$
|
20.03
|
|
|
$
|
25.45
|
|
Oil equivalent ($ per
boe)
|
$
|
28.22
|
|
|
$
|
27.27
|
|
Average Sales
Price (excluding unrealized gains (losses) on
derivatives):
|
|
|
|
Oil ($ per
bbl)
|
$
|
58.86
|
|
|
$
|
56.89
|
|
Natural gas ($ per
mcf)
|
$
|
3.07
|
|
|
$
|
3.49
|
|
NGL ($ per
bbl)
|
$
|
20.03
|
|
|
$
|
25.36
|
|
Oil equivalent ($ per
boe)
|
$
|
27.62
|
|
|
$
|
27.31
|
|
|
|
(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. 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)
|
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.
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
|
|
|
Three Months
Ended
March 31,
|
|
|
2019
|
|
2018*
|
|
|
|
|
|
Beginning cash and
cash equivalents
|
|
$
|
4
|
|
|
$
|
5
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
|
456
|
|
|
588
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
Drilling and
completion costs(a)
|
|
(515)
|
|
|
(420)
|
|
Business combination,
net
|
|
(353)
|
|
|
—
|
|
Acquisitions of
proved and unproved properties
|
|
(6)
|
|
|
(17)
|
|
Proceeds from
divestitures of proved and unproved properties
|
|
26
|
|
|
319
|
|
Additions to other
property and equipment
|
|
(9)
|
|
|
(3)
|
|
Proceeds from sales
of other property and equipment
|
|
1
|
|
|
68
|
|
Proceeds from sales
of investments
|
|
—
|
|
|
74
|
|
Net cash provided
by (used in) investing activities
|
|
(856)
|
|
|
21
|
|
|
|
|
|
|
Net cash provided
by (used in) financing activities
|
|
404
|
|
|
(610)
|
|
Change in cash and
cash equivalents
|
|
4
|
|
|
(1)
|
|
Ending cash and
cash equivalents
|
|
$
|
8
|
|
|
$
|
4
|
|
|
* Financial
information for 2018 has been recast to reflect the retrospective
application of the successful efforts method of
accounting.
|
|
|
(a)
|
Includes capitalized
interest of $6 million and $4 million for the three months ended
March 31, 2019 and 2018, respectively.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
($ in millions)
(unaudited)
|
|
|
Three Months Ended
March 31, 2019
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Net income (loss)
available to common stockholders (GAAP)
|
|
$
|
156
|
|
|
$
|
(200)
|
|
|
$
|
(44)
|
|
Effect of dilutive
securities
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted earnings
(losses) available to common stockholders
(GAAP)(a)
|
|
$
|
156
|
|
|
$
|
(200)
|
|
|
$
|
(44)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
281
|
|
|
—
|
|
|
281
|
|
Gains on sales of
assets
|
|
—
|
|
|
(19)
|
|
|
(19)
|
|
Other operating
expense(b)
|
|
51
|
|
|
10
|
|
|
61
|
|
Impairments
|
|
1
|
|
|
—
|
|
|
1
|
|
Losses on
investments
|
|
1
|
|
|
—
|
|
|
1
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(15)
|
|
|
(15)
|
|
Other
|
|
(2)
|
|
|
—
|
|
|
(2)
|
|
Income tax
benefit(c)
|
|
(314)
|
|
|
—
|
|
|
(314)
|
|
Adjusted net
income (loss) available to common stockholders(d)
(Non-GAAP)
|
|
174
|
|
|
(224)
|
|
|
(50)
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
—
|
|
|
23
|
|
Earnings allocated to
participating securities
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
income (loss) attributable to Chesapeake(d)(a)
(Non-GAAP)
|
|
$
|
197
|
|
|
$
|
(224)
|
|
|
$
|
(27)
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED NET INCOME (LOSS) PER SHARE
AVAILABLE TO
COMMON STOCKHOLDERS
(unaudited)
|
|
|
Three Months Ended
March 31, 2019
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Net income (loss)
per share available to common stockholders (GAAP)
|
|
$
|
0.11
|
|
|
$
|
(0.14)
|
|
|
$
|
(0.03)
|
|
Effect of dilutive
securities
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted earnings
(losses) per common stockholder (GAAP)(a)
|
|
$
|
0.11
|
|
|
$
|
(0.14)
|
|
|
$
|
(0.03)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
0.20
|
|
|
—
|
|
|
0.20
|
|
Gains on sales of
assets
|
|
—
|
|
|
(0.01)
|
|
|
(0.01)
|
|
Other operating
expense(b)
|
|
0.04
|
|
|
—
|
|
|
0.04
|
|
Impairments
|
|
—
|
|
|
—
|
|
|
—
|
|
Losses on
investments
|
|
—
|
|
|
—
|
|
|
—
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(0.01)
|
|
|
(0.01)
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
Income tax
benefit(c)
|
|
(0.23)
|
|
|
—
|
|
|
(0.23)
|
|
Adjusted net
income (loss) per share available to common
stockholders(d) (Non-GAAP)
|
|
0.12
|
|
|
(0.16)
|
|
|
(0.04)
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
0.02
|
|
|
—
|
|
|
0.02
|
|
Earnings allocated to
participating securities
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
income (loss) per share attributable to Chesapeake(d)(a)
(Non-GAAP)
|
|
$
|
0.14
|
|
|
$
|
(0.16)
|
|
|
$
|
(0.02)
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
($ in
millions)
(unaudited)
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Net income (loss)
available to common stockholders (GAAP)
|
|
$
|
268
|
|
|
$
|
(274)
|
|
|
$
|
(6)
|
|
Effect of dilutive
securities
|
|
36
|
|
|
(36)
|
|
|
—
|
|
Diluted earnings
(losses) available to common stockholders
(GAAP)(a)
|
|
$
|
304
|
|
|
$
|
(310)
|
|
|
$
|
(6)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
119
|
|
|
—
|
|
|
119
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
—
|
|
|
5
|
|
Gains on sales of
assets
|
|
—
|
|
|
(19)
|
|
|
(19)
|
|
Other operating
expense
|
|
8
|
|
|
(8)
|
|
|
—
|
|
Impairments
|
|
—
|
|
|
10
|
|
|
10
|
|
Gains on
investments
|
|
(139)
|
|
|
—
|
|
|
(139)
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(16)
|
|
|
(16)
|
|
Other
|
|
1
|
|
|
—
|
|
|
1
|
|
Income tax
expense(e)
|
|
—
|
|
|
—
|
|
|
—
|
|
Adjusted net
income (loss) available to common stockholders(d)
(Non-GAAP)
|
|
336
|
|
|
(343)
|
|
|
(7)
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
—
|
|
|
23
|
|
Earnings allocated to
participating securities
|
|
2
|
|
|
(2)
|
|
|
—
|
|
Total adjusted net
income (loss) attributable to Chesapeake(d)(a)
(Non-GAAP)
|
|
$
|
361
|
|
|
$
|
(345)
|
|
|
$
|
16
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED NET INCOME (LOSS) PER SHARE
AVAILABLE TO
COMMON STOCKHOLDERS
(unaudited)
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
Net income (loss)
per share available to common stockholders (GAAP)
|
|
$
|
0.30
|
|
|
$
|
(0.31)
|
|
|
$
|
(0.01)
|
|
Effect of dilutive
securities
|
|
(0.01)
|
|
|
0.01
|
|
|
—
|
|
Diluted earnings
(losses) per common stockholder (GAAP)(a)
|
|
$
|
0.29
|
|
|
$
|
(0.30)
|
|
|
$
|
(0.01)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
0.11
|
|
|
0.02
|
|
|
0.13
|
|
Restructuring and
other termination costs
|
|
0.04
|
|
|
—
|
|
|
0.04
|
|
Provision for legal
contingencies, net
|
|
—
|
|
|
0.01
|
|
|
0.01
|
|
Gains on sales of
assets
|
|
—
|
|
|
(0.02)
|
|
|
(0.02)
|
|
Other operating
expense
|
|
0.01
|
|
|
(0.01)
|
|
|
—
|
|
Impairments
|
|
—
|
|
|
0.01
|
|
|
0.01
|
|
Gains on
investments
|
|
(0.13)
|
|
|
(0.02)
|
|
|
(0.15)
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(0.02)
|
|
|
(0.02)
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
Income tax
expense(e)
|
|
—
|
|
|
—
|
|
|
—
|
|
Adjusted net
income (loss) per share available to common
stockholders(d) (Non-GAAP)
|
|
0.32
|
|
|
(0.33)
|
|
|
(0.01)
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
0.02
|
|
|
0.01
|
|
|
0.03
|
|
Earnings allocated to
participating securities
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
income (loss) per share attributable to Chesapeake(d)(a)
(Non-GAAP)
|
|
$
|
0.34
|
|
|
$
|
(0.32)
|
|
|
$
|
0.02
|
|
|
|
(a)
|
Our presentation of
diluted net income (loss) available to common stockholders and
diluted adjusted net income (loss) per share excludes 206 million
shares considered antidilutive for the three months ended March 31,
2019 and 2018. The number of shares used for the non-GAAP
calculation was determined in a manner consistent with
GAAP.
|
|
|
(b)
|
As a result of the
merger with Chesapeake, most WildHorse Resource Development
Corporation executives and employees were terminated. These
executives and employees were entitled to severance benefits of
approximately $38 million in accordance with certain provisions of
existing employment agreements that were triggered by the change in
control.
|
|
|
(c)
|
For the three months
ending March 31, 2019, we recorded a net deferred tax liability of
$314 million associated with the acquisition of WildHorse Resource
Development Corporation. As a result of recording this net
deferred tax liability through business combination accounting, we
released a corresponding amount of the valuation allowance that we
maintain against our net deferred tax asset position. This
release resulted in an income tax benefit of $314 million. The
effective tax rate for the quarter ended March 31, 2019 was
93.7%. Further, no income tax expense or benefit is shown for
the adjustments being made to arrive at adjusted net income (loss)
available to common stockholders as a result of not recording an
income tax expense or benefit on current period results due to
maintaining a full valuation allowance against our net deferred tax
asset position.
|
|
|
(d)
|
Adjusted net income
(loss) available to common stockholders and total adjusted net
income (loss) attributable to Chesapeake, both in the aggregate and
per dilutive share, are not measures of financial performance under
GAAP, and should not be considered as an alternative to, or more
meaningful than, net income (loss) available to common stockholders
or earnings (loss) per share. Adjusted net income (loss) available
to common stockholders and adjusted earnings (loss) per share
exclude certain items that management believes affect the
comparability of operating results. The company believes these
adjusted financial measures are a useful adjunct to earnings
calculated in accordance with GAAP because:
|
|
|
|
|
|
|
(i)
|
Management uses
adjusted net income (loss) available to common stockholders to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies.
|
|
|
|
|
|
|
(ii)
|
Adjusted net income
(loss) available to common stockholders is more comparable to
earnings estimates provided by securities analysts.
|
|
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items.
|
|
|
Because adjusted net
income (loss) available to common stockholders and total adjusted
net income (loss) attributable to Chesapeake exclude some, but not
all, items that affect net income (loss) available to common
stockholders and total adjusted net income (loss) attributable to
Chesapeake may vary among companies, our calculation of adjusted
net income (loss) available to common stockholders and total
adjusted net income (loss) attributable to Chesapeake may not be
comparable to similarly titled financial measures of other
companies.
|
|
|
(e)
|
No income tax effect
from the adjustments has been included in determining adjusted net
income for the three months ended March 31, 2018. Our effective tax
rate was 0% due to our valuation allowance position.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED
EBITDAX
($ in millions)
(unaudited)
|
|
|
Three Months Ended
March 31, 2019
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
|
$
|
502
|
|
|
$
|
(46)
|
|
|
$
|
456
|
|
Changes in assets and
liabilities
|
|
78
|
|
|
15
|
|
|
93
|
|
Interest
expense
|
|
135
|
|
|
26
|
|
|
161
|
|
Exploration
expense
|
|
—
|
|
|
6
|
|
|
6
|
|
Stock-based
compensation
|
|
(6)
|
|
|
—
|
|
|
(6)
|
|
Losses on
investments
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Net income
attributable to noncontrolling interest
|
|
(1)
|
|
|
1
|
|
|
—
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(15)
|
|
|
(15)
|
|
Other
items
|
|
(19)
|
|
|
1
|
|
|
(18)
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
|
$
|
688
|
|
|
$
|
(12)
|
|
|
$
|
676
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
|
$
|
656
|
|
|
$
|
(68)
|
|
|
$
|
588
|
|
Changes in assets and
liabilities
|
|
(104)
|
|
|
16
|
|
|
(88)
|
|
Interest
expense
|
|
123
|
|
|
39
|
|
|
162
|
|
Exploration
expense
|
|
—
|
|
|
13
|
|
|
13
|
|
Stock-based
compensation
|
|
(9)
|
|
|
—
|
|
|
(9)
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
—
|
|
|
5
|
|
Net income
attributable to noncontrolling interest
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(16)
|
|
|
(16)
|
|
Other
items
|
|
25
|
|
|
—
|
|
|
25
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
|
$
|
733
|
|
|
$
|
(16)
|
|
|
$
|
717
|
|
|
|
(a)
|
Adjusted EBITDAX is
not a measure of financial performance under GAAP, and should not
be considered as an alternative to, or more meaningful than, cash
flow provided by operations prepared in accordance with GAAP.
Adjusted EBITDAX excludes certain items that management believes
affect the comparability of operating results. The company believes
this non-GAAP financial measure is a useful adjunct to cash flow
provided by operations because:
|
|
|
|
|
(i)
|
Management uses
adjusted EBITDAX to evaluate the company's operational trends and
performance relative to other oil and natural gas producing
companies.
|
|
|
|
|
(ii)
|
Adjusted EBITDAX 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
EBITDAX excludes some, but not all, items that affect net income,
our calculations of adjusted EBITDAX may not be comparable to
similarly titled measures of other companies.
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDAX
($ in millions)
(unaudited)
|
|
|
Three Months Ended
March 31, 2019
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
NET INCOME (LOSS)
(GAAP)
|
|
$
|
180
|
|
|
$
|
(201)
|
|
|
$
|
(21)
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Interest
expense
|
|
135
|
|
|
26
|
|
|
161
|
|
Income tax
benefit
|
|
(314)
|
|
|
—
|
|
|
(314)
|
|
Depreciation,
depletion and amortization
|
|
357
|
|
|
162
|
|
|
519
|
|
Exploration
expense
|
|
—
|
|
|
24
|
|
|
24
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
281
|
|
|
—
|
|
|
281
|
|
Gains on sales of
assets
|
|
—
|
|
|
(19)
|
|
|
(19)
|
|
Other operating
expense
|
|
51
|
|
|
10
|
|
|
61
|
|
Impairments
|
|
1
|
|
|
—
|
|
|
1
|
|
Losses on
investments
|
|
1
|
|
|
—
|
|
|
1
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
1
|
|
|
—
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(15)
|
|
|
(15)
|
|
Other
|
|
(3)
|
|
|
—
|
|
|
(3)
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
|
$
|
688
|
|
|
$
|
(12)
|
|
|
$
|
676
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2018
|
|
|
Under
Full Cost
|
|
Successful
Efforts
Adjustments
|
|
As
Reported
|
NET INCOME
(GAAP)
|
|
$
|
294
|
|
|
$
|
(276)
|
|
|
$
|
18
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
Interest
expense
|
|
123
|
|
|
39
|
|
|
162
|
|
Depreciation,
depletion and amortization
|
|
286
|
|
|
173
|
|
|
459
|
|
Exploration
expense
|
|
—
|
|
|
81
|
|
|
81
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
119
|
|
|
—
|
|
|
119
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
|
5
|
|
|
—
|
|
|
5
|
|
Gains on sales of
assets
|
|
—
|
|
|
(19)
|
|
|
(19)
|
|
Other operating
expense
|
|
8
|
|
|
(8)
|
|
|
—
|
|
Impairments
|
|
—
|
|
|
10
|
|
|
10
|
|
Gains on
investments
|
|
(139)
|
|
|
—
|
|
|
(139)
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Other revenue (VPP
deferred revenue)
|
|
—
|
|
|
(16)
|
|
|
(16)
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
|
$
|
733
|
|
|
$
|
(16)
|
|
|
$
|
717
|
|
|
|
(a)
|
Adjusted EBITDAX is
not a measure of financial performance under GAAP, and should not
be considered as an alternative to, or more meaningful than, net
income (loss) prepared in accordance with GAAP. Adjusted EBITDAX
excludes certain items that management believes affect the
comparability of operating results. The company believes this
non-GAAP financial measure is a useful adjunct to net income (loss)
because:
|
|
|
|
|
(i)
|
Management uses
adjusted EBITDAX to evaluate the company's operational trends and
performance relative to other oil and natural gas producing
companies.
|
|
|
|
|
(ii)
|
Adjusted EBITDAX 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
EBITDAX excludes some, but not all, items that affect net income
(loss), our calculations of adjusted EBITDAX may not be comparable
to similarly titled measures of other companies.
|
CHESAPEAKE ENERGY
CORPORATION
MANAGEMENT'S OUTLOOK AS OF MAY 8, 2019
Chesapeake periodically provides guidance on certain factors
that affect the company's future financial performance. New
information or changes from the company's February 27, 2019 outlook are italicized
bold below.
|
Year
Ending
12/31/2019
|
Successful
Effort
Adjustments
|
Other
Adjustments
|
Year
Ending
12/31/2019
Revised
|
Absolute
Production:
|
|
|
|
|
Oil -
mmbbls
|
42.5 -
44.5
|
|
|
42.5 -
44.5
|
NGL -
mmbbls
|
13.0 -
15.0
|
|
|
13.0 -
15.0
|
Natural gas -
bcf
|
710 - 750
|
|
|
710 - 750
|
Total absolute
production - mmboe
|
174 - 184
|
|
|
174 - 184
|
Absolute daily rate -
mboe
|
475 - 505
|
|
|
475 - 505
|
Estimated Realized
Hedging Effects(a) (based on 5/3/19 strip
prices):
|
Oil -
$/bbl
|
($0.17)
|
|
($0.76)
|
($0.93)
|
Natural gas -
$/mcf
|
($0.07)
|
|
$0.10
|
$0.03
|
Estimated Basis to
NYMEX Prices:
|
|
|
|
|
Oil -
$/bbl
|
$1.20 -
$1.60
|
|
$0.40
|
$1.60 -
$2.00
|
Natural gas -
$/mcf
|
($0.10) -
($0.20)
|
|
|
($0.10) -
($0.20)
|
NGL - realizations as
a % of WTI
|
33% - 36%
|
|
|
33% - 36%
|
Operating Costs per
Boe of Projected Production:
|
Production
expense
|
$3.25 -
$3.50
|
|
|
$3.25 -
$3.50
|
Gathering, processing
and transportation expenses
|
$6.00 -
$6.50
|
|
|
$6.00 -
$6.50
|
Oil -
$/bbl
|
$3.35 -
$3.55
|
|
|
$3.35 -
$3.55
|
Natural Gas -
$/mcf
|
$1.20 -
$1.30
|
|
|
$1.20 -
$1.30
|
Production
taxes
|
$0.75 -
$0.85
|
|
$0.05
|
$0.80 -
$0.90
|
General and
administrative(b)
|
$1.50 -
$1.60
|
$0.25
|
|
$1.75 -
$1.85
|
Stock-based
compensation (non-cash)
|
$0.10 -
$0.20
|
|
|
$0.10 -
$0.20
|
Marketing Net
Margin and Other ($ in millions)(c)
|
($25) -
($45)
|
|
$10
|
($15) -
($35)
|
Adjusted
EBITDAX, based on 5/3/19 strip prices ($ in
millions)(d)
|
$2,500 -
$2,700
|
($45)
|
$95
|
$2,550 -
$2,750
|
Depreciation,
depletion and amortization expense
|
$5.50 -
$6.50
|
$6.00
|
|
$11.50 -
$12.50
|
Depreciation of other
assets
|
$0.40 -
$0.50
|
|
|
$0.40 -
$0.50
|
Interest
expense
|
$3.20 -
$3.40
|
$0.60
|
|
$3.80 -
$4.00
|
Exploration
expense ($ in millions, cash only)
|
|
$45
|
|
$40 -
$50
|
Book Tax
Rate
|
0%
|
|
|
0%
|
Capital
Expenditures ($ in millions)(e)
|
$2,175 -
$2,375
|
($90)
|
|
$2,085 -
$2,285
|
Capitalized
Interest ($ in millions)
|
$125
|
$(105)
|
|
$20
|
Total Capital
Expenditures ($ in millions)
|
$2,300 -
$2,500
|
|
|
$2,105 -
$2,305
|
|
|
(a)
|
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.
|
|
|
(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 approximately $8.7 million related to the buydown
of a transportation agreement and $58.6 million in deferred revenue
related to VPP9.
|
|
|
(d)
|
Adjusted EBITDAX 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 EBITDAX 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 EBITDAX 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 EBITDAX
include interest expense, income taxes, and depreciation, depletion
and amortization expense, exploration expense as well as one-time
items or items whose timing or amount cannot be reasonably
estimated.
|
|
|
(e)
|
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 May 3, 2019, including April
and May derivative contracts that have settled, approximately 70%
of the company's 2019 forecasted oil, natural gas and NGL
production revenue was hedged, including approximately 70% and 80%
of its remaining 2019 forecasted oil and natural gas production at
average prices of $58.75 per bbl and
$2.83 per mcf, respectively.
In addition, the company had downside protection on a portion of
its 2020 oil production at an average price of $60.10 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
|
|
|
|
|
Q2 2019
|
5
|
|
$
|
57.09
|
|
Q3 2019
|
6
|
|
$
|
60.22
|
|
Q4 2019
|
6
|
|
$
|
60.30
|
|
Total 2019
|
17
|
|
$
|
59.38
|
|
|
|
|
|
Total 2020
|
11
|
|
$
|
59.32
|
|
Oil Two-Way
Collars
|
|
Collars
(mmbbls)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q2 2019
|
1
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q3 2019
|
2
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q4 2019
|
1
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Total 2019
|
4
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
|
|
|
|
|
|
Total 2020
|
2
|
|
$
|
65.00
|
|
|
$
|
83.25
|
|
Oil
Puts
|
|
Volume
(mbbls)
|
|
Avg.
NYMEX
Bought Put
Price
|
|
|
|
|
Q2 2019
|
221
|
|
$
|
52.63
|
|
Q3 2019
|
587
|
|
$
|
54.14
|
|
Q4 2019
|
832
|
|
$
|
54.43
|
|
Total 2019
|
1,640
|
|
$
|
54.08
|
|
Oil
Swaptions
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Total 2020
|
4
|
|
$
|
62.45
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q2 2019
|
3
|
|
$
|
5.71
|
|
Q3 2019
|
2
|
|
$
|
5.67
|
|
Q4 2019
|
1
|
|
$
|
5.67
|
|
Total 2019
|
6
|
|
$
|
5.69
|
|
The company's natural gas hedging positions were as follows:
Open Natural Gas
Swaps
|
|
Swaps
(bcf)
|
|
Avg.
NYMEX
Price of
Swaps
|
|
|
|
|
Q2 2019
|
119
|
|
$
|
2.84
|
|
Q3 2019
|
115
|
|
$
|
2.84
|
|
Q4 2019
|
110
|
|
$
|
2.84
|
|
Total 2019
|
344
|
|
$
|
2.84
|
|
|
|
|
|
Total 2020
|
250
|
|
$
|
2.75
|
|
Natural Gas
Two-Way Collars
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q2 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q3 2019
|
10
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q4 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Total 2019
|
28
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Natural Gas
Three-Way Collars
|
|
Collars
(bcf)
|
|
Avg.
NYMEX
Sold Put
Price
|
|
Avg.
NYMEX
Bought Put
Price
|
|
Avg.
NYMEX
Sold
Call Price
|
|
|
|
|
|
|
|
|
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
|
66
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Natural Gas Net
Written Call Options
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q2 2019
|
6
|
|
$
|
12.00
|
|
Q3 2019
|
6
|
|
$
|
12.00
|
|
Q4 2019
|
5
|
|
$
|
12.00
|
|
Total 2019
|
17
|
|
$
|
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)
|
|
|
|
|
Q2 2019
|
17
|
|
$
|
(0.84)
|
|
Q3 2019
|
15
|
|
$
|
(0.45)
|
|
Q4 2019
|
6
|
|
$
|
(0.39)
|
|
Total 2019
|
38
|
|
$
|
(0.62)
|
|
View original content to download
multimedia:http://www.prnewswire.com/news-releases/chesapeake-energy-corporation-reports-2019-first-quarter-financial-and-operational-results-300845932.html
SOURCE Chesapeake Energy Corporation