OKLAHOMA CITY, Aug. 6, 2019 /PRNewswire/ -- Chesapeake Energy
Corporation (NYSE:CHK) today reported financial and operational
results for the 2019 second quarter. Highlights include:
- Increasing Oil Production, Enhancing Capital Efficiency,
Growing Margins and Progressing Toward Sustainable Free Cash
Flow
-
- Delivered record oil production of 122,000 barrels (bbls) of
oil per day, year-over-year growth of 36%, or 10% adjusted for
asset purchases and sales; record oil mix of 25%
- Operating cost reductions further enhance margins
-
- Reduced cash operating expenses consisting of production,
gathering, processing and transportation (GP&T) and general and
administrative expenses by $57
million, or approximately $0.40 per barrel of oil equivalent (boe), when
compared to the prior year quarter
- Highest second quarter operating margin per boe since 2014
- Capital efficiency improvements redefine economics of Brazos
Valley assets
-
- Projected 2019 total savings of $250 to $280
million; eliminated approximately $600,000 in costs per well; recognized up to
$2 million in savings on certain
wells
- Accelerating cycle times, with approximately 45 oil wells
planned to be placed to sales in the second half of 2019 compared
to 28 wells in the first half
- Expanded Eagle Ford higher-margin black oil window by
approximately 230 locations
- Maximizing Value of Diverse Portfolio Through
Returns-Focused Capital Allocation
-
- Maintaining oil growth trajectory on flat capital
-
- Oil production poised to increase in the second half of 2019 as
~170 oil wells expected to be placed to sales, an increase of
approximately 50% over the first half of 2019
- Projected to grow oil production by double-digits in 2020 on
approximately flat year-over-year capex, yielding approximately
flat adjusted EBITDAX at current NYMEX strip pricing and current
hedge position
- Reducing capital allocation to gas assets, forecasting
double-digit gas decline in 2020
- Prudently Managing Maturities to Maintain Future
Liquidity
-
- Exchanged $884 million senior
notes maturing 2020 through 2021 into new senior notes maturing
2026
- Reduced maturities prior to 2022 to approximately
$600 million
- $1.6 billion of liquidity
available under the Chesapeake parent credit facility
- Approximately 85% of 2019 forecasted oil, natural gas and
NGL revenue hedged at prices significantly above the current
strip
Doug Lawler, Chesapeake's
President and Chief Executive Officer, commented, "Driven by the
integration of our Brazos Valley asset, steady growth from the PRB
and improved base production performance from South Texas and the Mid-Continent, Chesapeake
produced approximately 122,000 barrels of oil per day, the highest
quarterly oil production in the company's history, and oil
production comprised approximately 25% of our total production mix,
also a company record. As highlighted above, we have a significant
oil growth runway in 2019 and accordingly, we are raising the
mid-point of our full-year oil production guidance by approximately
250,000 barrels. In addition, our focus on cash cost leadership has
resulted in reducing our full-year guidance for GP&T and
production expenses. We believe the trajectory of our oil volume
growth and related higher-margin cash flow from those volumes will
move higher as we enter 2020.
"As we formulate our initial 2020 plans, we expect to allocate
more capital to oil growth areas, with less capital going toward
our gas assets. As a result, with an approximately flat capital
program to 2019, we project our 2020 oil volumes will show
double-digit percentage growth over 2019, while our gas volumes
will show a double-digit percentage decline, yet our projected
adjusted EBITDAX remains approximately the same at 2019 levels
using today's lower NYMEX strip pricing and current hedge position.
We look forward to driving further value from our scale, diverse
portfolio and capital discipline in 2020 and beyond."
2019 Second Quarter Results
For the 2019 second quarter, Chesapeake reported net income of
$98 million and net income available
to common stockholders of $75
million, or $0.05 per diluted
share. Adjusting for items typically excluded by securities
analysts, the 2019 second quarter adjusted net loss attributable to
Chesapeake was $158 million or
$0.10 per share while adjusted
EBITDAX was $612 million.
Reconciliations of financial measures calculated in accordance with
GAAP to non-GAAP measures are provided on pages 15-19 of this
release.
Average daily production for the 2019 second quarter was
approximately 496,000 boe and consisted of approximately 122,000
bbls of oil, 2.034 billion cubic feet (bcf) of natural gas and
35,000 bbls of natural gas liquids (NGL). Average daily production
for the 2018 second quarter was approximately 530,000 boe and
consisted of approximately 90,000 bbls of oil, 2.311 bcf of natural
gas and 55,000 bbls of NGL. Oil production represented
approximately 25% of the company's 2019 second quarter aggregate
production compared to 17% in the 2018 second quarter.
Despite lower average prices for our oil, natural gas and NGL
sold, Chesapeake's cash margins increased significantly in the 2019
second quarter compared to the 2018 second quarter, primarily due
to a higher oil production mix and a decrease in GP&T and
general and administrative expenses. Chesapeake reduced its cash
operating expenses on an absolute basis by $57 million, or approximately $0.40 per boe.
Capital Spending Overview
Chesapeake invested total capital expenditures of approximately
$559 million during the 2019 second
quarter, including capitalized interest of $6 million, compared to approximately
$530 million in the 2018 second
quarter. The increase in capital expenditures in the 2019 second
quarter was largely attributable to an increase in net wells spud,
completed and connected. See tables below for a summary of
activity and expenditures.
|
Three Months
Ended
June 30,
|
|
2019
|
|
2018
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
Operated activity
comparison
|
|
|
|
|
|
|
|
Average rig
count
|
13
|
|
18
|
|
12
|
|
17
|
Wells spud
|
67
|
|
92
|
|
56
|
|
79
|
Wells
completed
|
70
|
|
92
|
|
56
|
|
85
|
Wells
connected
|
65
|
|
85
|
|
63
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
June
30,
|
|
2019
|
|
2018
|
Type of cost ($ in
millions)
|
|
|
|
Drilling and
completion capital expenditures
|
$
|
526
|
|
|
$
|
513
|
|
Leasehold and
additions to other PP&E
|
27
|
|
|
12
|
|
Subtotal capital
expenditures
|
$
|
553
|
|
|
$
|
525
|
|
Capitalized
interest
|
6
|
|
|
5
|
|
Total capital
expenditures
|
$
|
559
|
|
|
$
|
530
|
|
Balance Sheet and Liquidity
As of June 30, 2019, Chesapeake's
principal amount of debt outstanding inclusive of Brazos Valley
debt was approximately $10.161
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 and the $353 million of
net cash consideration paid as part of the WildHorse acquisition on
February 1, 2019. As of June 30, 2019, the company had borrowed
$1.372 billion under the $3.0 billion Chesapeake credit facility, utilized
approximately $54 million for various
letters of credit and had additional borrowing capacity of
approximately $1.574 billion. Under
the $1.3 billion Brazos Valley credit
facility, the company had borrowed $686
million and had additional borrowing capacity of
approximately $614 million. The
borrowing bases of both credit facilities were re-affirmed in
May 2019 with the next
re-determination dates scheduled for the 2019 fourth quarter.
During the 2019 second quarter, 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 and repaid approximately
$380 million of its Floating Rate
Senior Notes due 2019 at maturity. As a result, Chesapeake
currently has remaining maturities in 2020 and 2021 of $301 million and $294
million, respectively.
Chesapeake has protected a significant amount of its remaining
2019 revenue through hedging. As of July 31,
2019, including July and August derivative contracts that
have settled, approximately 85% of the company's remaining 2019
forecasted oil, natural gas and NGL production revenue was hedged,
including approximately 79% and 78% of its remaining 2019
forecasted oil and natural gas production at average prices of
$59.38 per bbl and $2.83 per thousand cubic feet (mcf),
respectively. Additionally, Chesapeake has basis protection on
approximately 4.1 million barrels (mmbbls) of its remaining
projected 2019 Eagle Ford oil production at a premium to WTI of
approximately $5.85 per bbl.
In 2020, Chesapeake currently has downside protection on
approximately 14.8 mmbbls of its projected oil production at an
average price of $59.93 per bbl and
on approximately 264.7 bcf of its projected gas production at an
average price of $2.76 per mcf.
Operations Update
Chesapeake's average daily production for the 2019 second
quarter was approximately 496,000 boe compared to approximately
530,000 boe in the 2018 second quarter. The following tables show
average daily production and average sales prices received
(excluding gains/losses on derivatives) by the company's operating
areas for the 2019 and 2018 second quarters.
|
Three Months Ended
June 30, 2019
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
—
|
|
|
—
|
|
|
929
|
|
|
2.33
|
|
|
—
|
|
|
—
|
|
|
155
|
|
|
31
|
|
|
13.99
|
|
Haynesville
|
—
|
|
|
—
|
|
|
751
|
|
|
2.39
|
|
|
—
|
|
|
—
|
|
|
125
|
|
|
25
|
|
|
14.36
|
|
Eagle Ford
|
58
|
|
|
65.82
|
|
|
152
|
|
|
2.69
|
|
|
19
|
|
|
12.78
|
|
|
102
|
|
|
21
|
|
|
43.89
|
|
Brazos
Valley
|
35
|
|
|
63.34
|
|
|
55
|
|
|
1.81
|
|
|
5
|
|
|
9.33
|
|
|
49
|
|
|
10
|
|
|
47.57
|
|
Powder River
Basin
|
20
|
|
|
57.05
|
|
|
89
|
|
|
2.26
|
|
|
5
|
|
|
16.30
|
|
|
40
|
|
|
8
|
|
|
35.58
|
|
Mid-Continent
|
9
|
|
|
58.12
|
|
|
59
|
|
|
2.03
|
|
|
6
|
|
|
16.97
|
|
|
25
|
|
|
5
|
|
|
30.53
|
|
Retained
assets(a)
|
122
|
|
|
63.09
|
|
|
2,035
|
|
|
2.35
|
|
|
35
|
|
|
13.50
|
|
|
496
|
|
|
100
|
|
|
26.13
|
|
Divested
assets
|
—
|
|
|
—
|
|
|
(1)
|
|
|
4.66
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
122
|
|
|
63.04
|
|
|
2,034
|
|
|
2.35
|
|
|
35
|
|
|
13.43
|
|
|
496
|
|
|
100
|
%
|
|
26.12
|
|
|
|
|
Three Months Ended
June 30, 2018
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
—
|
|
|
—
|
|
|
805
|
|
|
2.31
|
|
|
—
|
|
|
—
|
|
|
134
|
|
|
25
|
|
|
13.85
|
|
Haynesville
|
—
|
|
|
—
|
|
|
829
|
|
|
2.63
|
|
|
—
|
|
|
—
|
|
|
139
|
|
|
26
|
|
|
15.80
|
|
Eagle Ford
|
61
|
|
|
70.52
|
|
|
143
|
|
|
3.22
|
|
|
19
|
|
|
26.58
|
|
|
103
|
|
|
20
|
|
|
50.70
|
|
Powder River
Basin
|
8
|
|
|
67.37
|
|
|
57
|
|
|
2.18
|
|
|
4
|
|
|
27.12
|
|
|
22
|
|
|
4
|
|
|
36.78
|
|
Mid-Continent
|
10
|
|
|
66.77
|
|
|
64
|
|
|
2.38
|
|
|
5
|
|
|
24.41
|
|
|
25
|
|
|
5
|
|
|
36.74
|
|
Retained
assets(a)
|
79
|
|
|
69.70
|
|
|
1,898
|
|
|
2.52
|
|
|
28
|
|
|
26.29
|
|
|
423
|
|
|
80
|
|
|
26.03
|
|
Divested
assets
|
11
|
|
|
63.50
|
|
|
413
|
|
|
2.76
|
|
|
27
|
|
|
25.18
|
|
|
107
|
|
|
20
|
|
|
23.68
|
|
Total
|
90
|
|
|
68.92
|
|
|
2,311
|
|
|
2.56
|
|
|
55
|
|
|
25.74
|
|
|
530
|
|
|
100
|
%
|
|
25.56
|
|
|
(a)
|
Includes assets
retained as of June 30, 2019.
|
Brazos Valley: Driving significant capital efficiencies,
business unit expected to be free cash flow positive in
2019
Chesapeake has driven significant changes and improvements
through the first six months of its ownership of the Brazos Valley
asset, which was acquired on February 1,
2019. Since taking over daily operations, Chesapeake has
realized savings of approximately $600,000 per well, with savings of up to
$2 million per well on certain
individual wells, compared to the previous operator due to better
drilling and completion techniques, faster cycle times and lower
oilfield service costs.
The company is currently utilizing four rigs in the Brazos
Valley area, placed 24 wells on production (four Austin Chalk gas wells and 20 Eagle Ford oil
wells) during the 2019 second quarter and expects to place 26
wells, all in the Eagle Ford oil window, on production during the
2019 third quarter. In 2019, the company has already placed 10
wells to sales that have reached maximum 24-hour production rates
of more than 900 bbls of oil per day, compared to three wells that
reached that level in the same time period in 2018. Of those 10
wells, seven wells have reached maximum 24-hour production rates of
more than 1,000 bbls of oil per day. All but one of these wells
incorporated Chesapeake's new enhanced flow back techniques. These
results, combined with stronger base production, have resulted in
production that has exceeded the company's internal expectations
since the acquisition.
Additionally, Chesapeake has redefined its understanding of the
fluid windows on the acreage, resulting in a larger Eagle Ford oil
window than originally thought. The expansion of the black oil
window, based on subsurface analytics and validated by production
data from wells drilled in the 2019 first quarter, increased the
company's confidence of approximately 230 additional locations in
the black oil window. With an expected higher oil cut from these
locations, the economics of these wells are projected to be
significantly stronger when compared to the company's wells in the
volatile oil window or dry gas window areas of the play.
Chesapeake is evaluating options to be a shipper on a crude
pipeline that will deliver the company's Brazos Valley oil volumes
into the Houston, Texas market
beginning in the 2020 fourth quarter. Chesapeake is also pursuing a
new gathering agreement in the area that would reduce the current
reliance on trucking oil volumes and improve its cost structure in
the region. The company expects to have this new gathering
agreement in place for the operating area during the second half of
2019.
Eagle Ford Shale: Stronger base production exceeds internal
forecasts
In the company's Eagle Ford Shale position in South Texas, base production performance has
been strong due to adjusted well-spacing and optimized completion
designs. Chesapeake's operated sales volumes were affected by
planned third-party processing plant maintenance, which reduced
sales volumes for approximately one week in June, yet the business
unit was still able to exceed internal forecasts for the quarter
due to its stronger base production. Chesapeake is currently
utilizing four rigs in the area, which were located on large ranch
projects during the 2019 second quarter. As a result, 17 wells were
placed on production during the 2019 second quarter and the pace
will accelerate to 42 wells to be placed on production during the
2019 third quarter as these larger projects are completed.
Powder River Basin: Steadily growing high-margin oil
production
In the PRB, where the company moved a sixth rig in April 2019, Chesapeake placed 16 wells on
production during the 2019 second quarter and expects to place 26
wells on production during the 2019 third quarter. Development in
the Turner formation continues on pace and the field's gas-to-oil
ratio is moving lower as more wells are focused on the oil window.
Appraisal well results continue to expand field limits, including
the company's first "wine rack" test in the western portion of the
Turner area in an attempt to better access stacked pays. Chesapeake
recently completed the first new Niobrara well in the northern area of the
field since 2014 and production testing will take place in
August 2019, with two more
Niobrara wells planned for later
in the year. The company's first Mowry volatile oil window test is
also scheduled for later in 2019.
In the 2019 second quarter, Chesapeake connected its first pads
into a new oil gathering pipeline system that transports volumes to
Guernsey, Wyoming. New and
existing pads across the field are being connected to the gathering
system weekly, resulting in meaningful GP&T expense savings
going forward. As a result, more than 50% of the company's produced
PRB oil is now flowing on the gathering system and is expected to
grow up to 75% in the second half of the year. Also during the
quarter, Chesapeake secured transportation that allows its PRB oil
volumes to receive Gulf Coast pricing. Beginning in the 2020 fourth
quarter, the company expects to be able to deliver certain oil
volumes on a pipeline system, which has the ability to access both
markets in Cushing, Oklahoma and
Corpus Christi, Texas.
Marcellus Shale: Improving capital efficiency through
disciplined capital spending
Chesapeake continues to create significant free cash flow in the
Marcellus Shale in northeast Pennsylvania, driven by strong new well
performance as a result of refined spacing, longer laterals and
optimized completion designs. These capital efficient volumes,
coupled with base production strength and access to better realized
in-basin pricing, continue to make this a strong free cash flow
generator for Chesapeake. The company is currently utilizing two
drilling rigs, placed 14 wells on production during the 2019 second
quarter and expects to place 12 wells on production during the 2019
third quarter. The company expects to keep its gas-weighted capital
spending at prudent levels in 2020, including in its Marcellus
operating area. At the current activity level, Chesapeake has
approximately 10 years of drilling inventory at a break-even of
$1.50 to $1.75/mcf.
Haynesville Shale: Focused on optimizing base
production
In the Haynesville Shale in Louisiana, Chesapeake is currently operating
one rig, placed nine wells on production during the 2019 second
quarter and expects to place five wells on production during the
2019 third quarter. The company currently expects to reduce its
Haynesville Shale dry gas area rig count to zero in the near
future.
Mid-Continent: Capital allocated to higher-return areas,
high-graded program focused on 2020 activity
In the company's Mid-Continent operating area in Oklahoma, Chesapeake placed five wells on
production during the 2019 second quarter. The company dropped its
only operated rig in April 2019 and
expects to place no more wells on production through the end of the
year.
Key Financial and Operational Results
The table below summarizes Chesapeake's key financial and
operational results during the 2019 second quarter as compared to
results in prior periods. The three months ended June 30, 2019 include Brazos Valley operations.
The three months ended June 30, 2018
do not include Brazos Valley operations.
|
Three Months
Ended
June 30,
|
|
2019
|
|
2018
|
Barrels of oil
equivalent production (in mboe)
|
45,165
|
|
|
48,263
|
|
Barrels of oil
equivalent production (mboe/d)
|
496
|
|
|
530
|
|
Oil production (in
mbbl/d)
|
122
|
|
|
90
|
|
Average realized oil
price ($/bbl)(a)
|
61.44
|
|
|
57.16
|
|
Natural gas
production (in mmcf/d)
|
2,034
|
|
|
2,311
|
|
Average realized
natural gas price ($/mcf)(a)
|
2.48
|
|
|
2.64
|
|
NGL production (in
mbbl/d)
|
35
|
|
|
55
|
|
Average realized NGL
price ($/bbl)(a)
|
13.43
|
|
|
24.97
|
|
Production expenses
($/boe)
|
3.68
|
|
|
2.86
|
|
Gathering, processing
and transportation expenses ($/boe)
|
6.00
|
|
|
7.04
|
|
Oil -
($/bbl)
|
2.42
|
|
|
3.22
|
|
Natural Gas -
($/mcf)
|
1.23
|
|
|
1.29
|
|
NGL -
($/bbl)
|
5.01
|
|
|
8.46
|
|
Production taxes
($/boe)
|
0.88
|
|
|
0.55
|
|
Exploration expenses
($ in millions)
|
15
|
|
|
20
|
|
General and
administrative expenses ($/boe)(b)
|
1.79
|
|
|
1.98
|
|
General and
administrative expenses (stock-based compensation) (non-cash)
($/boe)
|
0.20
|
|
|
0.19
|
|
Depreciation,
depletion, and amortization ($/boe)
|
12.84
|
|
|
9.74
|
|
Interest expense
($/boe)(c)
|
3.85
|
|
|
3.21
|
|
Marketing net margin
($ in millions)(d)
|
(19)
|
|
|
(14)
|
|
Net cash provided by
operating activities ($ in millions)
|
397
|
|
|
363
|
|
Net cash provided by
operating activities ($/boe)
|
8.79
|
|
|
7.52
|
|
Net income (loss) ($
in millions)
|
98
|
|
|
(249)
|
|
Net income (loss)
available to common stockholders ($ in millions)
|
75
|
|
|
(272)
|
|
Net income (loss) per
share available to common stockholders – diluted ($)
|
0.05
|
|
|
(0.30)
|
|
Adjusted EBITDAX ($
in millions)(e)
|
612
|
|
|
518
|
|
Adjusted EBITDAX
($/boe)
|
13.55
|
|
|
10.73
|
|
Adjusted net loss
attributable to Chesapeake ($ in millions)(f)
|
(158)
|
|
|
(118)
|
|
Adjusted net loss
attributable to Chesapeake per share - diluted
($)(g)
|
(0.10)
|
|
|
(0.13)
|
|
|
|
(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)
|
Marketing net margin
is marketing gross margin of ($24) million and ($19) million for
the three months ended June 30, 2019 and 2018, excluding non-cash
amortization of $5 million related to the buy down 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
19. This is a non-GAAP measure. See reconciliation of cash provided
by operating activities to adjusted EBITDAX on page 18.
|
|
|
(f)
|
Defined as net income
(loss) attributable to Chesapeake, as adjusted to remove the
effects of certain items detailed on page 15. This is a non-GAAP
measure. See reconciliations of net income (loss) to adjusted net
income (loss) available to Chesapeake on pages 15 - 17.
|
|
|
(g)
|
Our presentation of
diluted adjusted net loss attributable to Chesapeake per share
excludes 207 million shares for the three months ended June 30,
2019 and 2018, which are considered antidilutive when calculating
diluted earnings per share.
|
|
|
2019 Second Quarter Financial and Operational Results
Conference Call Update
The conference call to discuss the company's financial and
operational results has been scheduled on Tuesday, August 6 at 9:00
am EDT. The telephone number to access the conference call
is 1-888-317-6003 or 1-412-317-6061 for international callers. The
passcode for the call is 6482113. 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 and number of wells to be placed into
production, anticipated timing of the Brazos Valley business unit
becoming cash flow positive, expected oil growth trajectory,
anticipated timing of execution of new gathering agreement,
expected oil volume growth in connection with new oil gathering
system and pipeline system, 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.
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions
except per share data)
(unaudited)
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
2019
|
|
2018*
|
|
2019
|
|
2018*
|
REVENUES AND
OTHER:
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL(a)
|
$
|
1,454
|
|
|
$
|
982
|
|
|
$
|
2,383
|
|
|
$
|
2,225
|
|
Marketing
|
916
|
|
|
1,273
|
|
|
2,149
|
|
|
2,519
|
|
Total
Revenues
|
2,370
|
|
|
2,255
|
|
|
4,532
|
|
|
4,744
|
|
Other
|
15
|
|
|
16
|
|
|
30
|
|
|
32
|
|
Gains on sales of
assets
|
1
|
|
|
18
|
|
|
20
|
|
|
37
|
|
Total Revenues and
Other
|
2,386
|
|
|
2,289
|
|
|
4,582
|
|
|
4,813
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL production
|
166
|
|
|
138
|
|
|
298
|
|
|
285
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
271
|
|
|
340
|
|
|
545
|
|
|
696
|
|
Production
taxes
|
40
|
|
|
26
|
|
|
74
|
|
|
57
|
|
Exploration
|
15
|
|
|
20
|
|
|
39
|
|
|
101
|
|
Marketing
|
940
|
|
|
1,292
|
|
|
2,170
|
|
|
2,560
|
|
General and
administrative
|
89
|
|
|
105
|
|
|
192
|
|
|
192
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
3
|
|
|
4
|
|
|
3
|
|
|
9
|
|
Depreciation,
depletion and amortization
|
580
|
|
|
471
|
|
|
1,099
|
|
|
930
|
|
Impairments
|
1
|
|
|
54
|
|
|
2
|
|
|
64
|
|
Other operating
(income) expense
|
3
|
|
|
(1)
|
|
|
64
|
|
|
(1)
|
|
Total Operating
Expenses
|
2,108
|
|
|
2,449
|
|
|
4,486
|
|
|
4,931
|
|
INCOME (LOSS) FROM
OPERATIONS
|
278
|
|
|
(160)
|
|
|
96
|
|
|
(118)
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
Interest
expense
|
(175)
|
|
|
(155)
|
|
|
(336)
|
|
|
(317)
|
|
Gains (losses) on
investments
|
(23)
|
|
|
—
|
|
|
(24)
|
|
|
139
|
|
Other
income
|
18
|
|
|
57
|
|
|
27
|
|
|
56
|
|
Total Other
Expense
|
(180)
|
|
|
(98)
|
|
|
(333)
|
|
|
(122)
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
98
|
|
|
(258)
|
|
|
(237)
|
|
|
(240)
|
|
Income tax
benefit
|
—
|
|
|
(9)
|
|
|
(314)
|
|
|
(9)
|
|
NET INCOME
(LOSS)
|
98
|
|
|
(249)
|
|
|
77
|
|
|
(231)
|
|
Net income
attributable to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
|
98
|
|
|
(249)
|
|
|
77
|
|
|
(232)
|
|
Preferred stock
dividends
|
(23)
|
|
|
(23)
|
|
|
(46)
|
|
|
(46)
|
|
NET INCOME (LOSS)
AVAILABLE TO COMMON STOCKHOLDERS
|
$
|
75
|
|
|
$
|
(272)
|
|
|
$
|
31
|
|
|
$
|
(278)
|
|
EARNINGS (LOSS)
PER COMMON SHARE:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.05
|
|
|
$
|
(0.30)
|
|
|
$
|
0.02
|
|
|
$
|
(0.31)
|
|
Diluted
|
$
|
0.05
|
|
|
$
|
(0.30)
|
|
|
$
|
0.02
|
|
|
$
|
(0.31)
|
|
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
|
|
|
Basic
|
1,628
|
|
|
909
|
|
|
1,505
|
|
|
908
|
|
Diluted
|
1,628
|
|
|
909
|
|
|
1,505
|
|
|
908
|
|
|
* Financial
information for 2018 has been recast to reflect the retrospective
application of the successful efforts method of
accounting.
|
|
(a)
|
See page 13 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)
|
|
June 30,
2019
|
|
December 31,
2018
|
|
|
|
|
Cash and cash
equivalents
|
$
|
4
|
|
|
$
|
4
|
|
Other current
assets
|
1,380
|
|
|
1,594
|
|
Total Current
Assets
|
1,384
|
|
|
1,598
|
|
|
|
|
|
Property and
equipment, net
|
14,845
|
|
|
10,818
|
|
Other long-term
assets
|
311
|
|
|
319
|
|
Total
Assets
|
$
|
16,540
|
|
|
$
|
12,735
|
|
|
|
|
|
Current
liabilities
|
$
|
2,220
|
|
|
$
|
2,887
|
|
Long-term debt,
net
|
9,701
|
|
|
7,341
|
|
Other long-term
liabilities
|
389
|
|
|
374
|
|
Total
Liabilities
|
12,310
|
|
|
10,602
|
|
|
|
|
|
Preferred
stock
|
1,671
|
|
|
1,671
|
|
Noncontrolling
interests
|
39
|
|
|
41
|
|
Common stock and
other stockholders' equity
|
2,520
|
|
|
421
|
|
Total
Equity
|
4,230
|
|
|
2,133
|
|
|
|
|
|
Total Liabilities
and Equity
|
$
|
16,540
|
|
|
$
|
12,735
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
2019
|
|
2018*
|
|
2019
|
|
2018*
|
|
|
|
|
|
|
|
|
Beginning cash and
cash equivalents
|
$
|
8
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
397
|
|
|
363
|
|
|
853
|
|
|
951
|
|
|
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Drilling and
completion costs(a)
|
(555)
|
|
|
(508)
|
|
|
(1,070)
|
|
|
(928)
|
|
Business combination,
net
|
—
|
|
|
—
|
|
|
(353)
|
|
|
—
|
|
Acquisitions of
proved and unproved properties
|
(11)
|
|
|
(85)
|
|
|
(17)
|
|
|
(102)
|
|
Proceeds from
divestitures of proved and unproved properties
|
56
|
|
|
65
|
|
|
82
|
|
|
384
|
|
Additions to other
property and equipment
|
(9)
|
|
|
(2)
|
|
|
(18)
|
|
|
(5)
|
|
Proceeds from sales
of other property and equipment
|
3
|
|
|
6
|
|
|
4
|
|
|
74
|
|
Proceeds from sales
of investments
|
—
|
|
|
—
|
|
|
—
|
|
|
74
|
|
Net cash used in
investing activities
|
(516)
|
|
|
(524)
|
|
|
(1,372)
|
|
|
(503)
|
|
|
|
|
|
|
|
|
|
Net cash provided
by (used in) financing activities
|
115
|
|
|
160
|
|
|
519
|
|
|
(450)
|
|
Change in cash and
cash equivalents
|
(4)
|
|
|
(1)
|
|
|
—
|
|
|
(2)
|
|
Ending cash and
cash equivalents
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
* 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 $5 million for the three months ended
June 30, 2019 and 2018, respectively, and includes capitalized
interest of $12 million and $9 million for the six months ended
June 30, 2019 and 2018, respectively.
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
SUPPLEMENTAL DATA
– OIL, NATURAL GAS AND NGL PRODUCTION AND SALES
PRICES
(unaudited)
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Net
Production:
|
|
|
|
|
|
|
|
Oil
(mmbbl)
|
11
|
|
|
8
|
|
|
21
|
|
|
16
|
|
Natural gas
(bcf)
|
185
|
|
|
210
|
|
|
367
|
|
|
432
|
|
NGL
(mmbbl)
|
3
|
|
|
5
|
|
|
7
|
|
|
10
|
|
Oil equivalent
(mmboe)
|
45
|
|
|
48
|
|
|
89
|
|
|
98
|
|
Average daily
production (mboe)
|
496
|
|
|
530
|
|
|
490
|
|
|
542
|
|
Oil, Natural Gas
and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
Oil sales
|
$
|
700
|
|
|
$
|
567
|
|
|
$
|
1,266
|
|
|
$
|
1,104
|
|
Natural gas
sales
|
436
|
|
|
538
|
|
|
1,031
|
|
|
1,244
|
|
NGL sales
|
43
|
|
|
128
|
|
|
112
|
|
|
245
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,179
|
|
|
$
|
1,233
|
|
|
$
|
2,409
|
|
|
$
|
2,593
|
|
|
|
|
|
|
|
|
|
Financial
Derivatives:
|
|
|
|
|
|
|
|
Oil derivatives –
realized losses(a)
|
$
|
(18)
|
|
|
$
|
(97)
|
|
|
$
|
(8)
|
|
|
(161)
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
24
|
|
|
17
|
|
|
(12)
|
|
|
84
|
|
NGL derivatives –
realized losses(a)
|
—
|
|
|
(3)
|
|
|
—
|
|
|
(4)
|
|
Total realized gains
(losses) on financial derivatives
|
$
|
6
|
|
|
$
|
(83)
|
|
|
$
|
(20)
|
|
|
$
|
(81)
|
|
|
|
|
|
|
|
|
|
Oil derivatives –
unrealized gains (losses)(b)
|
104
|
|
|
(105)
|
|
|
(165)
|
|
|
(127)
|
|
Natural gas
derivatives – unrealized gains (losses)(b)
|
165
|
|
|
(52)
|
|
|
159
|
|
|
(151)
|
|
NGL derivatives –
unrealized losses(b)
|
—
|
|
|
(11)
|
|
|
—
|
|
|
(9)
|
|
Total unrealized
gains (losses) on financial derivatives
|
$
|
269
|
|
|
$
|
(168)
|
|
|
$
|
(6)
|
|
|
$
|
(287)
|
|
|
|
|
|
|
|
|
|
Total financial
derivatives
|
$
|
275
|
|
|
$
|
(251)
|
|
|
$
|
(26)
|
|
|
$
|
(368)
|
|
|
|
|
|
|
|
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,454
|
|
|
$
|
982
|
|
|
$
|
2,383
|
|
|
$
|
2,225
|
|
Average Sales
Price (excluding gains (losses) on derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
63.04
|
|
|
$
|
68.92
|
|
|
$
|
60.59
|
|
|
$
|
66.76
|
|
Natural gas ($ per
mcf)
|
$
|
2.35
|
|
|
$
|
2.56
|
|
|
$
|
2.81
|
|
|
$
|
2.88
|
|
NGL ($ per
bbl)
|
$
|
13.43
|
|
|
$
|
25.74
|
|
|
$
|
16.86
|
|
|
$
|
25.60
|
|
Oil equivalent ($ per
boe)
|
$
|
26.12
|
|
|
$
|
25.56
|
|
|
$
|
27.15
|
|
|
$
|
26.43
|
|
Average Sales
Price (excluding unrealized gains (losses) on
derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
61.44
|
|
|
$
|
57.16
|
|
|
$
|
60.23
|
|
|
$
|
57.03
|
|
Natural gas ($ per
mcf)
|
$
|
2.48
|
|
|
$
|
2.64
|
|
|
$
|
2.77
|
|
|
$
|
3.07
|
|
NGL ($ per
bbl)
|
$
|
13.43
|
|
|
$
|
24.97
|
|
|
$
|
16.86
|
|
|
$
|
25.16
|
|
Oil equivalent ($ per
boe)
|
$
|
26.25
|
|
|
$
|
23.82
|
|
|
$
|
26.92
|
|
|
$
|
25.60
|
|
|
|
(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
RECONCILIATION OF
ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
($ in
millions)
(unaudited)
|
|
Three Months Ended
June 30,
|
|
2019
|
|
2018
|
|
$
|
|
$/Share
|
|
$
|
|
$/Share
|
Net income (loss)
available to common stockholders (GAAP)
|
$
|
75
|
|
|
$
|
0.05
|
|
|
$
|
(272)
|
|
|
$
|
(0.30)
|
|
Effect of dilutive
securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted earnings
(losses) available to common stockholders
(GAAP)(a)
|
$
|
75
|
|
|
$
|
0.05
|
|
|
$
|
(272)
|
|
|
$
|
(0.30)
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
(268)
|
|
|
(0.16)
|
|
|
168
|
|
|
0.18
|
|
Provision for legal
contingencies, net
|
3
|
|
|
—
|
|
|
4
|
|
|
—
|
|
Gains on sales of
assets
|
(1)
|
|
|
—
|
|
|
(18)
|
|
|
(0.02)
|
|
Other operating
(income) expense
|
3
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
Impairments
|
1
|
|
|
—
|
|
|
54
|
|
|
0.06
|
|
Losses on
investments
|
23
|
|
|
0.01
|
|
|
—
|
|
|
—
|
|
Other revenue (VPP
deferred revenue)
|
(15)
|
|
|
(0.01)
|
|
|
(16)
|
|
|
(0.02)
|
|
Other
|
(2)
|
|
|
—
|
|
|
(60)
|
|
|
(0.06)
|
|
Income tax
benefit(b)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Adjusted net loss
available to common stockholders(c)
(Non-GAAP)
|
(181)
|
|
|
(0.11)
|
|
|
(141)
|
|
|
(0.16)
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
23
|
|
|
0.01
|
|
|
23
|
|
|
0.03
|
|
Earnings allocated to
participating securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
loss attributable to Chesapeake(a)(c)
(Non-GAAP)
|
$
|
(158)
|
|
|
$
|
(0.10)
|
|
|
$
|
(118)
|
|
|
$
|
(0.13)
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME (LOSS) AVAILABLE TO COMMON
STOCKHOLDERS
($ in millions)
(unaudited)
|
|
Six Months Ended
June 30,
|
|
2019
|
|
2018
|
|
$
|
|
$/Share
|
|
$
|
|
$/Share
|
Net income (loss)
available to common stockholders (GAAP)
|
$
|
31
|
|
|
$
|
0.02
|
|
|
$
|
(278)
|
|
|
$
|
(0.31)
|
|
Effect of dilutive
securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted earnings
(losses) available to common stockholders
(GAAP)(a)
|
$
|
31
|
|
|
$
|
0.02
|
|
|
$
|
(278)
|
|
|
$
|
(0.31)
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
13
|
|
|
0.01
|
|
|
287
|
|
|
0.32
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
38
|
|
|
0.04
|
|
Provision for legal
contingencies, net
|
3
|
|
|
—
|
|
|
9
|
|
|
0.01
|
|
Gains on sales of
assets
|
(20)
|
|
|
(0.01)
|
|
|
(37)
|
|
|
(0.04)
|
|
Other operating
(income) expense(d)
|
64
|
|
|
0.04
|
|
|
(1)
|
|
|
—
|
|
Impairments
|
2
|
|
|
—
|
|
|
64
|
|
|
0.07
|
|
(Gains) losses on
investments
|
24
|
|
|
0.02
|
|
|
(139)
|
|
|
(0.15)
|
|
Other revenue (VPP
deferred revenue)
|
(30)
|
|
|
(0.02)
|
|
|
(32)
|
|
|
(0.04)
|
|
Other
|
(4)
|
|
|
—
|
|
|
(59)
|
|
|
(0.06)
|
|
Income tax
benefit(e)
|
(314)
|
|
|
(0.21)
|
|
|
—
|
|
|
—
|
|
Adjusted net loss
available to common stockholders(c)
(Non-GAAP)
|
(231)
|
|
|
(0.15)
|
|
|
(148)
|
|
|
(0.16)
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
46
|
|
|
0.03
|
|
|
46
|
|
|
0.05
|
|
Earnings allocated to
participating securities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
loss attributable to Chesapeake(a)(c)
(Non-GAAP)
|
$
|
(185)
|
|
|
$
|
(0.12)
|
|
|
$
|
(102)
|
|
|
$
(0.11)
|
|
|
|
(a)
|
Our presentation of
diluted net earnings (losses) available to common stockholders per
share and diluted adjusted net loss per share excludes 207 million
shares considered antidilutive for the three months and six months
ended June 30, 2019 and 2018. The number of shares used for the
non-GAAP calculation was determined in a manner consistent with
GAAP.
|
|
|
|
(b)
|
No income tax effect
from the adjustments has been included in determining adjusted net
income for the three months ended June 30, 2019 and 2018. Our
effective tax rate was 0% due to our valuation allowance
position.
|
|
|
|
(c)
|
Adjusted net loss
available to common stockholders and total adjusted net 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
loss available to common stockholders and total adjusted net loss
attributable to Chesapeake exclude some, but not all, items that
affect net income (loss) available to common stockholders our
calculations of adjusted net loss available to common stockholders
and total adjusted net loss attributable to Chesapeake may not be
comparable to similarly titled measures of other
companies.
|
|
|
(d)
|
The six months ended
June 30, 2019 includes $26MM in integration and acquisition costs
as a result of Chesapeake's merger with WildHorse Resource
Development Corporation (WRD). Additionally, most WRD executives
and employees were terminated and 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.
|
|
|
(e)
|
For the six months
ended June 30, 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 $314
million. Further, no income tax expense or benefit is shown
for the adjustments being made to arrive at adjusted net income
(loss) available to common stockholders as a result of not
recording an income tax expense or benefit on current period
results due to maintaining a full valuation allowance against our
net deferred tax asset position.
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF CASH PROVIDED BY OPERATING ACTIVITIES TO ADJUSTED
EBITDAX
($ in millions)
(unaudited)
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
$
|
397
|
|
|
$
|
363
|
|
|
$
|
853
|
|
|
$
|
951
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Changes in assets and
liabilities
|
44
|
|
|
26
|
|
|
137
|
|
|
(62)
|
|
Other revenue (VPP
deferred revenue)
|
(15)
|
|
|
(16)
|
|
|
(30)
|
|
|
(32)
|
|
Interest
expense
|
175
|
|
|
155
|
|
|
336
|
|
|
317
|
|
Exploration
|
8
|
|
|
15
|
|
|
14
|
|
|
28
|
|
Stock-based
compensation
|
(11)
|
|
|
(9)
|
|
|
(17)
|
|
|
(18)
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
Losses on
investments
|
7
|
|
|
—
|
|
|
6
|
|
|
—
|
|
Net income
attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Other
items
|
7
|
|
|
(16)
|
|
|
(11)
|
|
|
14
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
$
|
612
|
|
|
$
|
518
|
|
|
$
|
1,288
|
|
|
$
|
1,235
|
|
|
|
(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 operating activities 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 operating activities 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
RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDAX
($ in millions)
(unaudited)
|
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
NET INCOME (LOSS)
(GAAP)
|
|
$
|
98
|
|
|
$
|
(249)
|
|
|
$
|
77
|
|
|
$
|
(231)
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
175
|
|
|
155
|
|
|
336
|
|
|
317
|
|
Income tax
benefit
|
|
—
|
|
|
(9)
|
|
|
(314)
|
|
|
(9)
|
|
Depreciation,
depletion and amortization
|
|
580
|
|
|
471
|
|
|
1,099
|
|
|
930
|
|
Exploration
|
|
15
|
|
|
20
|
|
|
39
|
|
|
101
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
(268)
|
|
|
168
|
|
|
13
|
|
|
287
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
Provision for legal
contingencies, net
|
|
3
|
|
|
4
|
|
|
3
|
|
|
9
|
|
Gains on sales of
assets
|
|
(1)
|
|
|
(18)
|
|
|
(20)
|
|
|
(37)
|
|
Other operating
(income) expense
|
|
3
|
|
|
(1)
|
|
|
64
|
|
|
(1)
|
|
Impairments
|
|
1
|
|
|
54
|
|
|
2
|
|
|
64
|
|
(Gains) losses on
investments
|
|
23
|
|
|
—
|
|
|
24
|
|
|
(139)
|
|
Net income
attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Other revenue (VPP
deferred revenue)
|
|
(15)
|
|
|
(16)
|
|
|
(30)
|
|
|
(32)
|
|
Other
|
|
(2)
|
|
|
(61)
|
|
|
(5)
|
|
|
(61)
|
|
Adjusted EBITDAX
(Non-GAAP)(a)
|
|
$
|
612
|
|
|
$
|
518
|
|
|
$
|
1,288
|
|
|
$
|
1,235
|
|
|
|
(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 AUGUST 6, 2019
|
|
Chesapeake
periodically provides guidance on certain factors that affect the
company's future financial performance. New information or changes
from the company's May 8, 2019 outlook are italicized
bold below.
|
|
|
Year
Ending
12/31/2019
|
Absolute
Production:
|
|
Oil -
mmbbls
|
43.0 -
44.5
|
NGL -
mmbbls
|
13.0 -
15.0
|
Natural gas -
bcf
|
725 -
750
|
Total absolute
production - mmboe
|
177 -
184
|
Absolute daily
rate - mboe
|
484 -
505
|
Estimated
Realized Hedging Effects(a) (based on 7/31/19 strip
prices)
|
|
Oil -
$/bbl
|
$0.35
|
Natural gas -
$/mcf
|
$0.14
|
Estimated Basis to
NYMEX Prices:
|
|
Oil -
$/bbl
|
$1.95 -
$2.15
|
Natural gas -
$/mcf
|
($0.10) -
($0.20)
|
NGL -
realizations as a % of WTI
|
25% -
28%
|
Operating Costs per
boe of Projected Production:
|
|
Production
expense
|
$3.20 -
$3.40
|
Gathering,
processing and transportation expenses
|
$5.90 -
$6.40
|
Oil -
$/bbl
|
$2.95 -
$3.15
|
Natural Gas -
$/mcf
|
$1.20 -
$1.30
|
Production
taxes
|
$0.80 -
$0.90
|
General and
administrative(b)
|
$1.75 -
$1.85
|
Stock-based
compensation (non-cash)
|
$0.10 -
$0.20
|
Marketing Net Margin
and Other ($ in millions)(c)
|
($15) -
($35)
|
Adjusted
EBITDAX, based on 7/31/19 strip prices ($ in
millions)(d)
|
$2,450 -
$2,650
|
Depreciation,
depletion and amortization expense
|
$12.50 -
$13.50
|
Interest
expense
|
$3.80 -
$4.00
|
Exploration
expense ($ in millions, cash only)
|
$35 -
$45
|
Book Tax
Rate
|
0%
|
Capital Expenditures
($ in millions)(e)
|
$2,085 -
$2,285
|
Capitalized Interest
($ in millions)
|
$20
|
Total Capital
Expenditures ($ in millions)
|
$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.
|
|
|
(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, developmental
geological and geophysical costs, rig termination payments and
other property, plant and equipment. Excludes any additional proved
property acquisitions and expenditures classified as exploration
expense.
|
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 July 31, 2019, including
July and August derivative contracts that have settled,
approximately 85% of the company's 2019 forecasted oil, natural gas
and NGL production revenue was hedged, including approximately 79%
and 78% of its remaining 2019 forecasted oil and natural gas
production at average prices of $59.38 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 $59.93 per bbl and on a portion of its 2020 gas
production at an average price of $2.76 per mcf.
The company's crude oil hedging positions were as follows:
Open Crude Oil
Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
Price of
Swaps
|
|
|
|
|
Q3 2019
|
7
|
|
$
|
60.16
|
|
Q4 2019
|
7
|
|
$
|
60.24
|
|
Total 2019
|
14
|
|
$
|
60.20
|
|
|
|
|
|
Total 2020
|
13
|
|
$
|
59.21
|
|
|
|
Oil Two-Way
Collars
|
|
Volume
(mmbbls)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q3 2019
|
2
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Q4 2019
|
1
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
Total 2019
|
3
|
|
$
|
58.00
|
|
|
$
|
67.75
|
|
|
|
|
|
|
|
Total 2020
|
2
|
|
$
|
65.00
|
|
|
$
|
83.25
|
|
|
|
Oil
Puts
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
Bought Put
Price
|
|
|
|
|
Total 2019
|
1
|
|
$
|
54.13
|
|
|
|
Oil
Swaptions
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Total 2020
|
2
|
|
$
|
63.15
|
|
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q3 2019
|
2
|
|
$
|
5.97
|
|
Q4 2019
|
2
|
|
$
|
5.67
|
|
Total 2019
|
4
|
|
$
|
5.85
|
|
The company's natural gas hedging positions were as follows:
|
Open Natural Gas
Swaps
|
|
Volume
(bcf)
|
|
Avg.
NYMEX
Price of
Swaps
|
|
|
|
|
Q3 2019
|
137
|
|
$
|
2.83
|
|
Q4 2019
|
118
|
|
$
|
2.84
|
|
Total 2019
|
255
|
|
$
|
2.84
|
|
|
|
|
|
Total 2020
|
265
|
|
$
|
2.76
|
|
|
|
Natural Gas
Two-Way Collars
|
|
Volume
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q3 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q4 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Total 2019
|
18
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
|
|
Natural Gas
Three-Way Collars
|
|
Volume
(bcf)
|
|
Avg.
NYMEX
Sold Put
Price
|
|
Avg.
NYMEX
Bought Put
Price
|
|
Avg.
NYMEX
Sold Call
Price
|
|
|
|
|
|
|
|
|
Q4 2019
|
15
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Total 2019
|
15
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
|
|
Natural Gas Net
Written Call Options
|
|
Volume
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q3 2019
|
6
|
|
$
|
12.00
|
|
Q4 2019
|
5
|
|
$
|
12.00
|
|
Total 2019
|
11
|
|
$
|
12.00
|
|
|
|
|
|
Total 2020
|
22
|
|
$
|
12.00
|
|
|
|
Natural Gas Net
Written Call Swaptions
|
|
Volume
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Total 2020
|
106
|
|
$
|
2.77
|
|
|
|
|
|
Total 2021
|
15
|
|
$
|
2.80
|
|
|
|
|
|
Total 2022
|
15
|
|
$
|
2.80
|
|
|
|
Natural Gas Basis
Protection Swaps
|
|
Volume
(bcf)
|
|
Avg. NYMEX
plus/(minus)
|
|
|
|
|
Q3 2019
|
11
|
|
$
|
0.20
|
|
Q4 2019
|
15
|
|
$
|
(0.23)
|
|
Total 2019
|
26
|
|
$
|
(0.05)
|
|
|
|
|
|
Total 2020
|
15
|
|
$
|
(0.19)
|
|
|
|
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
(405) 935-8870
ir@chk.com
|
Gordon Pennoyer
(405) 935-8878
media@chk.com
|
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SOURCE Chesapeake Energy Corp.