HOUSTON, Feb. 24, 2021 /PRNewswire/ -- Callon Petroleum
Company (NYSE: CPE) ("Callon" or the "Company") today reported
results of operations for the three months and full-year ended
December 31, 2020.
Presentation slides accompanying this earnings release are
available on the Company's website at www.callon.com located on the
"Presentations" page within the Investors section of the site.
2020 Highlights
- Full-year 2020 production of 101.6 MBoe/d (63% oil), an
increase of 146% over 2019 volumes
- Year-end proved reserves of 475.9 MMBoe (61% oil)
- Generated net cash provided by operating activities of
$559.8 million and adjusted free cash
flow1 of $10.7 million,
including net cash provided by operating activities of $368.1 million and $122.6
million of adjusted free cash flow1 generation
over the last three quarters
- Loss available to common stockholders of $2.5 billion, or $63.79 per diluted share, driven by impairments
of evaluated oil and gas properties of $2.5
billion, adjusted EBITDA1 of $709.7 million, and adjusted income1
of $117.1 million or $2.86 per diluted share
- Lowered average drilling and completion cost per lateral foot
by approximately 35% from 2019 comparable well costs, driving total
operational capital expenditures of $488.6
million, meaningfully below budgeted levels
- Reduced total cash general and administrative expenses by more
than 60% from pro forma 20192 levels
- Lowered annual lease operating expense by more than
$30 million from pro forma
20192 levels through effective implementation of field
best practices
- Asset monetization proceeds and debt exchanges reduced total
debt balances by approximately $350
million since the second quarter of 2020
Fourth Quarter 2020 Highlights
- Fourth quarter 2020 production of 94.9 MBoe/d (62% oil), an
increase of 103% over fourth quarter 2019 volumes and a sequential
decrease of 7% including the impact of completed divestitures
- Generated $134.6 million of net
cash provided by operating activities and adjusted free cash
flow1 of $24.4
million
- Loss available to common stockholders of $505.1 million, or $12.71 per diluted share, driven by an impairment
of evaluated oil and gas properties of $585.8 million, adjusted EBITDA1 of
$167.8 million, and adjusted
income1 of $42.8 million
or $1.00 per diluted share
2021 Capital Plan Highlights
- Operational capital budget of up to $430
million, a 12% reduction relative to 2020 spending, with
approximately 70% allocated to Permian activity
- Annual production guidance of 90 - 92 MBoe/d (63% oil)
inclusive of estimated winter storm impacts of approximately 2
MBoe/d for the full year 2021
- Expected adjusted free cash flow1 generation of
approximately $150 million at
$50/Bbl oil (WTI benchmark)
Joe Gatto, President and Chief
Executive Officer commented, "In a year marked by extraordinary
volatility in commodity prices and workplace challenges created by
the COVID-19 pandemic, our newly integrated team executed
flawlessly on a revamped set of operational and financial
initiatives that ultimately delivered over $120 million of adjusted free cash flow since the
beginning of the second quarter, dramatically improving our
liquidity and absolute debt position. Importantly, these
accomplishments were complemented by significant achievements
related to employee safety and environmental emissions."
He continued, "Our medium-term development plans are squarely
focused on free cash flow generation and absolute debt reduction.
Given our leading operating margins and low-cost resource base, the
magnitude and pace of improvements in financial strength from
organic cash flows are highly differentiated in the sector. Our
2021 capital budget, inclusive of capitalized expenses, implies a
reinvestment rate3 of approximately 75% of discretionary
cash flow at $50 per barrel WTI price
and a free cash flow breakeven price of approximately $40 per barrel. We will continue to manage our
future capital reinvestment rate3 within a targeted
range of 65% to 75% under a range of pricing environments, which is
expected to generate adjusted free cash flow in a range of
$500 to $800
million over the next three years assuming WTI oil prices of
$50 to $60 per barrel. In addition, we are targeting
asset monetizations of approximately $125 to $225
million in 2021 to further our debt reduction goals, meeting
our original 2020 total divestiture targets after including
transactions completed last year. As divestiture market conditions
continue to improve, we are evaluating opportunities for
incremental, credit enhancing monetizations above our targeted
levels."
Environmental, Social, and Governance ("ESG") Updates
Callon advanced its sustainability initiatives during 2020 with
the Company achieving numerous milestones as detailed below:
- Issued an inaugural SASB aligned sustainability report
- Reduced flared natural gas volumes by 44%
- Achieved a 66% reduction in spill volumes
- Increased recycled water usage by 10%
- Set a new Callon record for safety with a total recordable
incident rate of under 0.55
- Named a top Houston workplace
for the fourth straight year by the Houston Chronicle
- Supported schools, food banks and first responders in our local
communities during the challenges of the global pandemic
- Enhanced board oversight of ESG by expanding the remit of the
Nominating and ESG Committee
Callon continues to advance various sustainability efforts and
expects to disclose new long-term targets for GHG emissions
reductions and a revamped executive compensation program aligned
with investor and corporate priorities in the near future.
Operations Update and Outlook
At December 31, 2020, Callon had 1,496 gross (1,320.6 net)
horizontal wells producing from established flow units in the
Permian and Eagle Ford. Net daily production for the three months
ended December 31, 2020 grew 103% to 94.9 MBoe/d (62% oil) as
compared to the same period of 2019. Full year production for 2020
averaged 101.6 MBoe/d (63% oil) reflecting growth of 146% over 2019
volumes.
For the three months ended December 31, 2020, Callon
drilled 22 gross (20.0 net) horizontal wells and placed a combined
16 gross (14.3 net) horizontal wells on production. Wells placed on
production during the quarter were completed in the Lower
Spraberry and Wolfcamp A in the Midland Basin and the Wolfcamp A
and Wolfcamp C in the Delaware
Basin.
Recently, severe winter storms affected field operations in both
the Permian and Eagle Ford resulting in the shut-in of nearly 100%
of our operated production. Currently, we have returned nearly all
of our Eagle Ford and Midland Basin wells to production and expect
to have all of our Delaware well
production returned by the end of February. The estimated
annualized impact of these deferrals is approximately 2,000 Boe/d.
This has been reflected in our updated production guidance for
2021. The impact to our drilling and completion operations were not
significant enough to alter our expectations for the full year
development schedule and any additional operational costs are
currently reflected in our lease operating expense guidance.
Currently, the Company has three active rigs with one each in
the Midland, Delaware, and Eagle
Ford. The Company recently deployed a second completion crew and
has operations taking place in the Delaware and Eagle Ford.
2021 Capital Expenditures Budget
Callon has established an operational capital expenditure budget
of $430.0 million for 2021 with
approximately 80% of spending directed towards drilling, completion
and equipment expenditures. The reduction of approximately
$60 million from 2020 levels reflects
a decrease in the number of drilled wells as well as a full year of
achieved capital synergies. Roughly 70% of this development capital
will be spent on Permian activity with the remaining balance
allocated to the Eagle Ford. Permian development activity will
predominantly feature co-development of the Wolfcamp A and B in the
Delaware and the Lower Spraberry
and Wolfcamp A in the Midland. The Eagle Ford program remains
focused solely on the primary target zone, the Lower Eagle Ford
Shale, as technical evaluation continues on Austin Chalk potential for future delineation.
In total, the Company expects to drill 55 to 65 gross wells and
complete 90 to 100 gross wells.
Our scaled development plan for 2021 will continue to employ our
life of field development philosophy and benefit from our balanced
capital deployment strategy. We entered the year with a robust
backlog of drilled uncompleted wells ("DUCs"), after drilling over
90 wells in 2020, which will allow us to complete approximately 55
wells in the first half of the year. Although at a reduced number
from year end 2020, we now plan to maintain a meaningful DUC
inventory heading into 2022 to provide operational flexibility to
execute across a range of development planning scenarios. The
capital expenditures associated with this higher DUC inventory
contributed to the majority of the approximate $30 million increase relative to our previous
2021 capital estimates, in addition to selective project size
increases to improve capital efficiency and resource recovery.
These schedule refinements will position Callon for an improved
production trajectory in the medium term, adhering to our
reinvestment rate parameters, to increase free cash flow generation
potential.
The 2021 capital plan leverages the structural savings and
operational efficiencies achieved during 2020 from shared best
practices following the integration of Callon and Carrizo. Callon's
ability to reduce the average well cost by more than 35% on a
lateral foot basis since 2019 has yielded significant improvements
in capital efficiency. Lower capital costs paired with an improved
operating cost structure and moderated development program are
expected to provide a foundation of durable free cash flow
generated by a program that optimizes recoverable value while
avoiding over-capitalization of the resource base.
The remainder of our full year 2021 outlook is provided later in
this release under the section titled "2021 Guidance."
Capital Expenditures
For the year ended December 31, 2020, Callon incurred
$488.6 million in operational capital
expenditures on an accrual basis as compared to $515.1 million in 2019. For the three months
ended December 31, 2020, the Company incurred $87.5 million in operational capital expenditures
on an accrual basis, which represented a $49.1 million increase from the third quarter of
2020. Total capital expenditures, inclusive of capitalized
expenses, are detailed below on an accrual and cash basis:
|
|
Three Months Ended
December 31, 2020
|
|
|
Operational
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
|
Capital
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
|
|
(In
thousands)
|
Cash basis
(b)
|
|
$77,742
|
|
|
$25,201
|
|
|
$6,465
|
|
|
$109,408
|
|
Timing adjustments
(c)
|
|
8,317
|
|
|
(2,187)
|
|
|
—
|
|
|
6,130
|
|
Non-cash
items
|
|
1,429
|
|
|
—
|
|
|
2,390
|
|
|
3,819
|
|
Accrual
basis
|
|
$87,488
|
|
|
$23,014
|
|
|
$8,855
|
|
|
$119,357
|
|
|
|
(a)
|
Includes seismic,
land, technology, and other items.
|
(b)
|
Cash basis is
presented here to help users of financial information reconcile
amounts from the cash flow statement to the balance sheet by
accounting for timing related changes in working capital that align
with our development pace and rig count.
|
(c)
|
Includes timing
adjustments related to cash disbursements in the current period for
capital expenditures incurred in the prior period.
|
Operating and Financial Results
The following table presents summary information for the periods
indicated:
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
Total
production
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
|
|
|
|
Permian
|
|
3,445
|
|
|
3,441
|
|
|
2,934
|
|
Eagle Ford
|
|
1,980
|
|
|
2,434
|
|
|
300
|
|
Total oil
(MBbls)
|
|
5,425
|
|
|
5,875
|
|
|
3,234
|
|
|
|
|
|
|
|
|
Natural gas
(MMcf)
|
|
|
|
|
|
|
Permian
|
|
7,474
|
|
|
7,868
|
|
|
5,296
|
|
Eagle Ford
|
|
2,264
|
|
|
2,393
|
|
|
234
|
|
Total natural
gas (MMcf)
|
|
9,738
|
|
|
10,261
|
|
|
5,530
|
|
|
|
|
|
|
|
|
NGLs (MBbls)
|
|
|
|
|
|
|
Permian
|
|
1,331
|
|
|
1,423
|
|
|
93
|
|
Eagle Ford
|
|
353
|
|
|
379
|
|
|
42
|
|
Total NGLs
(MBbls)
|
|
1,684
|
|
|
1,802
|
|
|
135
|
|
|
|
|
|
|
|
|
Total production
(MBoe)
|
|
|
|
|
|
|
Permian
|
|
6,022
|
|
|
6,175
|
|
|
3,910
|
|
Eagle Ford
|
|
2,710
|
|
|
3,212
|
|
|
381
|
|
Total barrels
of oil equivalent (MBoe)
|
|
8,732
|
|
|
9,387
|
|
|
4,291
|
|
|
|
|
|
|
|
|
Total daily
production (Boe/d)
|
|
|
|
|
|
|
Permian
|
|
65,459
|
|
|
67,117
|
|
|
42,500
|
|
Eagle Ford
|
|
29,455
|
|
|
34,912
|
|
|
4,141
|
|
Total barrels
of oil equivalent (Boe/d)
|
|
94,914
|
|
|
102,029
|
|
|
46,641
|
|
Oil as % of total
daily production
|
|
62
|
%
|
|
63
|
%
|
|
75
|
%
|
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
Average realized
sales price (excluding impact of settled
derivatives)
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
|
|
|
|
|
Permian
|
|
$41.02
|
|
|
$39.42
|
|
|
$56.31
|
|
Eagle Ford
|
|
41.12
|
|
|
39.44
|
|
|
59.57
|
|
Total oil (per
Bbl)
|
|
$41.06
|
|
|
$39.43
|
|
|
$56.61
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
|
|
|
|
|
Permian
|
|
$1.68
|
|
|
$1.31
|
|
|
$1.96
|
|
Eagle Ford
|
|
2.65
|
|
|
1.99
|
|
|
2.44
|
|
Total natural
gas (per Mcf)
|
|
$1.91
|
|
|
$1.47
|
|
|
$1.98
|
|
|
|
|
|
|
|
|
NGL (per
Bbl)
|
|
|
|
|
|
|
Permian
|
|
$15.00
|
|
|
$12.68
|
|
|
$16.58
|
|
Eagle Ford
|
|
16.16
|
|
|
13.13
|
|
|
12.69
|
|
Total NGL (per
Bbl)
|
|
$15.24
|
|
|
$12.78
|
|
|
$15.37
|
|
|
|
|
|
|
|
|
Average realized
sales price (per Boe)
|
|
|
|
|
|
|
Permian
|
|
$28.87
|
|
|
$26.55
|
|
|
$45.30
|
|
Eagle Ford
|
|
34.36
|
|
|
32.92
|
|
|
49.81
|
|
Total average
realized sales price (per Boe)
|
|
$30.57
|
|
|
$28.73
|
|
|
$45.70
|
|
|
|
|
|
|
|
|
Average realized
sales price
(including impact of
settled derivatives)
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
$39.62
|
|
|
$39.00
|
|
|
$55.33
|
|
Natural gas (per
Mcf)
|
|
1.89
|
|
|
1.17
|
|
|
2.12
|
|
NGLs (per
Bbl)
|
|
15.24
|
|
|
12.78
|
|
|
15.37
|
|
Total
average realized sales price (per Boe)
|
|
$29.66
|
|
|
$28.14
|
|
|
$44.92
|
|
|
|
|
|
|
|
|
Revenues (in
thousands)(a)
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
Permian
|
|
$141,320
|
|
|
$135,648
|
|
|
$165,199
|
|
Eagle Ford
|
|
81,413
|
|
|
96,006
|
|
|
17,872
|
|
Total
oil
|
|
222,733
|
|
|
231,654
|
|
|
183,071
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
|
|
|
|
Permian
|
|
12,560
|
|
|
10,271
|
|
|
10,377
|
|
Eagle Ford
|
|
6,001
|
|
|
4,763
|
|
|
572
|
|
Total natural
gas
|
|
18,561
|
|
|
15,034
|
|
|
10,949
|
|
|
|
|
|
|
|
|
NGLs
|
|
|
|
|
|
|
Permian
|
|
19,964
|
|
|
18,049
|
|
|
1,542
|
|
Eagle Ford
|
|
5,704
|
|
|
4,976
|
|
|
533
|
|
Total
NGLs
|
|
25,668
|
|
|
23,025
|
|
|
2,075
|
|
|
|
|
|
|
|
|
Total
revenues
|
|
|
|
|
|
|
Permian
|
|
173,844
|
|
|
163,968
|
|
|
177,118
|
|
Eagle Ford
|
|
93,118
|
|
|
105,745
|
|
|
18,977
|
|
Total
revenues
|
|
$266,962
|
|
|
$269,713
|
|
|
$196,095
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
Additional per Boe
data
|
|
|
|
|
|
|
Sales price
(b)
|
|
|
|
|
|
|
Permian
|
|
$28.87
|
|
|
$26.55
|
|
|
$45.30
|
|
Eagle Ford
|
|
34.36
|
|
|
32.92
|
|
|
49.81
|
|
Total sales
price
|
|
$30.57
|
|
|
$28.73
|
|
|
$45.70
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
|
|
|
|
|
Permian
|
|
$4.43
|
|
|
$4.38
|
|
|
$5.66
|
|
Eagle Ford
|
|
6.77
|
|
|
5.86
|
|
|
8.38
|
|
Total lease
operating expense
|
|
$5.15
|
|
|
$4.89
|
|
|
$5.90
|
|
|
|
|
|
|
|
|
Production and ad
valorem taxes
|
|
|
|
|
|
|
Permian
|
|
$1.71
|
|
|
$1.57
|
|
|
$2.04
|
|
Eagle Ford
|
|
2.29
|
|
|
2.00
|
|
|
2.29
|
|
Total
production and ad valorem taxes
|
|
$1.89
|
|
|
$1.72
|
|
|
$2.06
|
|
|
|
|
|
|
|
|
Gathering,
transportation and processing
|
|
|
|
|
|
|
Permian
|
|
$2.42
|
|
|
$2.55
|
|
|
$—
|
|
Eagle Ford
|
|
2.25
|
|
|
2.00
|
|
|
—
|
|
Total
gathering, transportation and processing
|
|
$2.37
|
|
|
$2.36
|
|
|
$—
|
|
|
|
|
|
|
|
|
Operating
margin
|
|
|
|
|
|
|
Permian
|
|
$20.31
|
|
|
$18.05
|
|
|
$37.60
|
|
Eagle Ford
|
|
23.05
|
|
|
23.06
|
|
|
39.14
|
|
Total operating
margin
|
|
$21.16
|
|
|
$19.76
|
|
|
$37.74
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and amortization
|
|
$11.00
|
|
|
$12.17
|
|
|
$14.30
|
|
General and
administrative
|
|
$1.22
|
|
|
$0.88
|
|
|
$3.18
|
|
Adjusted G&A
1
|
|
|
|
|
|
|
Cash component
(c)
|
|
$0.86
|
|
|
$0.87
|
|
|
$2.41
|
|
Non-cash
component
|
|
$0.07
|
|
|
$0.18
|
|
|
$0.53
|
|
|
|
(a)
|
Excludes sales of oil
and gas purchased from third parties and sold to our
customers.
|
(b)
|
Excludes the impact
of settled derivatives.
|
(c)
|
Excludes the change
in fair value and amortization of share-based incentive awards and
other non-recurring expenses.
|
Revenue. For the quarter ended
December 31, 2020, Callon reported total revenue of
$267.0 million, which excluded
revenue from sales of commodities purchased from a third-party of
$29.0 million. Revenues including the
gain or loss from the settlement of derivative contracts ("Adjusted
Total Revenue"1) were $259.0
million, reflecting the impact of an $8.0 million loss from the settlement of
derivative contracts. Average daily production for the quarter was
94.9 MBoe/d compared to average daily production of 102.0 MBoe/d in
the third quarter of 2020. Average realized prices, including and
excluding the effects of hedging, are detailed above.
Commodity Derivatives. For the quarter ended
December 31, 2020, the net (gain) loss on commodity derivative
contracts includes the following (in thousands):
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
(Gain) loss on oil
derivatives
|
|
$70,317
|
|
(Gain) loss on
natural gas derivatives
|
|
(3,936)
|
|
(Gain) loss on NGL
derivatives
|
|
8
|
|
(Gain) loss on
commodity derivative contracts
|
|
$66,389
|
|
For the quarter ended December 31, 2020, the cash (paid)
received for commodity derivative settlements includes the
following (in thousands):
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
Cash (paid) received
on oil derivatives
|
|
($2,100)
|
|
Cash (paid) received
on natural gas derivatives
|
|
(784)
|
|
Cash (paid) received
for commodity derivative settlements
|
|
($2,884)
|
|
Lease Operating Expenses, including workover
("LOE"). LOE per Boe for the three months ended
December 31, 2020 was $5.15 per
Boe, compared to $4.89 per Boe in the
third quarter of 2020. The slight increase in LOE per Boe is
primarily from the decrease in sequential production as fixed costs
are spread over a lower production base.
Production and Ad Valorem Taxes. Production
and ad valorem taxes were $1.89 per
Boe for the three months ended December 31, 2020, representing
approximately 6% of revenue excluding revenue from sales of
commodities purchased from a third-party and before the impact of
derivative settlements.
Gathering, Transportation and Processing. Gathering,
transportation and processing for the three months ended
December 31, 2020 were $20.7
million as compared to $22.2
million in the third quarter of 2020 In 2020, the Company
began reporting gathering, transportation and processing separately
due to the assumption of processing agreements in the Carrizo
acquisition and certain contract modifications effective
January 1, 2020. As such, the Company
now records contractual fees associated with gathering, processing,
treating and compression, as well as any transportation fees
incurred to deliver the product to the purchaser, as gathering,
transportation and processing. These fees were historically
recorded as a reduction of revenue depending on when control
transferred to the purchaser.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
December 31, 2020 was $11.00 per
Boe compared to $12.17 per Boe in the
third quarter of 2020. The decrease in DD&A was primarily
driven by the impairment of evaluated oil and gas properties
recognized in the third quarter of 2020.
Impairment of Evaluated Oil and Gas Properties. Callon
recognized an impairment of evaluated oil and gas properties of
$585.8 million for the three months
ended December 31, 2020 due primarily to the continued decline
in the average realized prices for sales of oil and gas on the
first calendar day of each month during the year. For the three
months ended September 30, 2020, the
Company recognized an impairment of evaluated oil and gas
properties of $685.0 million.
General and Administrative Expense
("G&A"). G&A for the three months ended
December 31, 2020 and September 30,
2020 was $10.6 million, or
$1.22 per Boe, and $8.2 million, or $0.88 per Boe, respectively. G&A, excluding
certain non-cash incentive share-based compensation valuation
adjustments, ("Adjusted G&A1" ) was $8.1 million, or $0.93 per Boe, for the three months ended
December 31, 2020 compared to $9.8
million, or $1.04 per Boe, for
the third quarter of 2020. The cash component of Adjusted G&A
was $7.5 million, or $0.86 per Boe, for the three months ended
December 31, 2020 compared to $8.1
million, or $0.87 per Boe, for
the third quarter of 2020 primarily as a result of reduced labor
expense during the fourth quarter.
The following table reconciles total G&A to Adjusted G&A
- cash component, and full cash G&A (in thousands):
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
|
December 31,
2020
|
Total
G&A
|
|
$10,614
|
|
|
$8,224
|
|
|
$13,626
|
|
|
$37,187
|
|
Change in the fair
value of liability share-based awards (non-cash)
|
|
(2,500)
|
|
|
1,582
|
|
|
(1,010)
|
|
|
4,110
|
|
Adjusted G&A –
total
|
|
8,114
|
|
|
9,806
|
|
|
12,616
|
|
|
41,297
|
|
Restricted stock
share-based compensation (non-cash) and other non-recurring
expenses
|
|
(580)
|
|
|
(1,674)
|
|
|
(2,294)
|
|
|
(7,771)
|
|
Adjusted G&A –
cash component
|
|
$7,534
|
|
|
$8,132
|
|
|
$10,322
|
|
|
$33,526
|
|
|
|
|
|
|
|
|
|
|
Capitalized cash
G&A
|
|
6,465
|
|
|
6,831
|
|
|
8,782
|
|
|
27,606
|
|
Full cash
G&A
|
|
$13,999
|
|
|
$14,963
|
|
|
$19,104
|
|
|
$61,132
|
|
Income Tax. Callon provides for income taxes at a
federal statutory rate of 21% adjusted for permanent
differences expected to be realized. The Company recorded income
tax expense of $6.8 million for the
three months ended December 31, 2020, compared to zero income
tax expense for the three months ended September 30, 2020 as a result of an increase in
the deferred tax assets acquired in the Carrizo Acquisition due to
the filing of the final tax returns which provide the underlying
tax basis of Carrizo's assets and liabilities and the subsequent
valuation allowance against those deferred tax assets.
Loss Available to Common Stockholders. We recorded a
loss available to common stockholders for the three months ended
December 31, 2020 of $505.1
million, or $12.71 per diluted
share, as compared to a loss available to common stockholders of
$680.4 million, or $17.12 per diluted share, for the third quarter
of 2020. The losses were primarily due to the impairments of
evaluated oil and gas properties of $585.8
million and $685.0 million for
the three months ended December 31, 2020 and September 30, 2020, respectively.
Adjusted EBITDA. Adjusted EBITDA for the fourth
quarter of 2020 was $167.8 million as
compared to $170.9 million for the
third quarter of 2020. The decrease in adjusted EBITDA from the
third quarter of 2020 was primarily due to a decrease in production
partially offset by an increase in realized prices.
Proved Reserves
DeGolyer and MacNaughton prepared the estimates of Callon's
proved reserves as of December 31,
2020. As of December 31, 2020,
Callon's estimated net proved reserves were 475.9 MMBoe and
included 289.5 MMBbls of oil, 541.6 Bcf of natural gas, and 96.1
MMBbls of NGLs with a standardized measure of discounted future net
cash flows of $2.3 billion using
average realized prices for sales of oil, natural gas, and NGLs on
the first calendar day of each month during the year of
$37.44/Bbl for oil, $1.02/Mcf for natural gas, and $11.10/Bbl for NGLs. Utilizing the same reserve
database and development schedule, management's internal estimate
of PV-10 value4 at flat forward price realizations of
$49.00/Bbl for oil, $2.40/Mcf for natural gas, and $17.65/Bbl for NGLs is just over $4.6 billion. Both of these valuations assume a
more moderated pace of development than previously contemplated and
have been adjusted as such for less PUD bookings within the normal
five-year window.
Oil constituted approximately 61% of the Company's estimated
equivalent proved developed reserves as well as the Company's
estimated equivalent total proved reserves. The Company added 41.4
MMBoe of new reserves in extensions and discoveries through
development efforts in 2020, with a total of 91 gross (86.0 net)
wells drilled and 90 gross (81.4 net) wells completed.
The changes in Callon's estimated net proved reserves are as
follows:
|
|
Total
(MBoe)
|
Proved reserves at
December 31, 2019
|
|
540,012
|
|
Extensions and
discoveries
|
|
41,407
|
|
Revisions to previous
estimates
|
|
(52,227)
|
|
Sales of reserves in
place
|
|
(16,120)
|
|
Production
|
|
(37,193)
|
|
Proved reserves at
December 31, 2020
|
|
475,879
|
|
2020 Full Year Actuals
|
Full
Year
|
|
2020
Actual
|
Total production
(MBoe/d)
|
101.6
|
Oil
|
63%
|
NGL
|
19%
|
Natural gas
|
18%
|
Income statement
expenses (in millions, except where noted)
|
|
LOE, including
workovers
|
$194.1
|
Gathering,
transportation and processing
|
$77.3
|
Production and ad
valorem taxes (% of total oil, natural gas, and NGL
revenues)
|
6.4%
|
Adjusted G&A -
cash component (a)
|
$33.5
|
Adjusted G&A -
non-cash component (b)
|
$7.8
|
Cash interest expense,
net
|
$90.4
|
Capital
expenditures (in millions, accrual basis)
|
|
Total operational
capital (c)
|
$488.6
|
Capitalized interest
and G&A
|
$124.0
|
Gross operated
wells drilled / completed
|
91 / 90
|
|
|
(a)
|
Excludes the change
in fair value and amortization of share-based incentive awards and
other non-recurring expenses.
|
(b)
|
Amortization of
equity-settled, share based incentive awards and other
non-recurring expenses.
|
(c)
|
Includes facilities,
equipment, seismic, land and other items, excludes capitalized
expenses.
|
2021 Guidance
|
Full
Year
|
|
2021
Guidance
|
Total production
(MBoe/d)
|
90.0 -
92.0
|
Oil
|
63%
|
NGL
|
19%
|
Natural gas
|
18%
|
Income statement
expenses (in millions except where noted)
|
|
LOE, including
workovers
|
$190.0 -
$210.0
|
Gathering,
transportation and processing
|
$70.0 -
$80.0
|
Production and ad
valorem taxes (% of total oil, natural gas, and NGL
revenues)
|
6.5%
|
Adjusted G&A: cash
component (a)
|
$35.0 -
$45.0
|
Adjusted G&A:
non-cash component (b)
|
$5.0 -
$15.0
|
Cash interest expense,
net
|
$80.0 -
$90.0
|
Estimated effective
income tax rate
|
22%
|
Capital
expenditures (in millions, accrual basis)
|
|
Total operational
capital (c)
|
$430.0
|
Capitalized
interest
|
$95.0 -
$105.0
|
Capitalized
G&A
|
$28.0 -
$38.0
|
Gross operated
wells drilled / completed
|
55 - 65 / 90 -
100
|
|
|
(a)
|
Excludes the change
in fair value and amortization of share-based incentive awards and
other non-recurring expenses.
|
(b)
|
Amortization of
equity-settled, share based incentive awards and other
non-recurring expenses.
|
(c)
|
Includes facilities,
equipment, seismic, land and other items, excludes capitalized
expenses.
|
Hedge Portfolio Summary
As of February 19, 2021, Callon had the following
outstanding oil, natural gas and NGL derivative contracts:
|
For the Full Year
of
|
|
For the Full Year
of
|
|
Oil contracts
(WTI)
|
2021
|
|
2022
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
1,827,000
|
|
|
—
|
|
|
Weighted
average price per Bbl
|
$43.54
|
|
|
$—
|
|
|
Collar
contracts
|
|
|
|
|
Total volume
(Bbls)
|
11,202,775
|
|
|
1,355,000
|
|
|
Weighted
average price per Bbl
|
|
|
|
|
Ceiling (short
call)
|
$47.80
|
|
|
$60.00
|
|
|
Floor (long
put)
|
$39.95
|
|
|
$45.00
|
|
|
Short call
contracts
|
|
|
|
|
Total volume
(Bbls)
|
4,825,300
|
|
(a)
|
—
|
|
|
Weighted
average price per Bbl
|
$63.62
|
|
|
$—
|
|
|
Short call swaption
contracts
|
|
|
|
|
Total volume
(Bbls)
|
455,000
|
|
(b)
|
1,825,000
|
|
(b)
|
Weighted
average price per Bbl
|
$47.00
|
|
|
$52.18
|
|
|
|
|
|
|
|
Oil contracts (ICE
Brent)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
505,000
|
|
(c)
|
—
|
|
|
Weighted
average price per Bbl
|
$37.34
|
|
|
$—
|
|
|
Collar
contracts
|
|
|
|
|
Total volume
(Bbls)
|
730,000
|
|
|
—
|
|
|
Weighted
average price per Bbl
|
|
|
|
|
Ceiling (short
call)
|
$50.00
|
|
|
$—
|
|
|
Floor (long
put)
|
$45.00
|
|
|
$—
|
|
|
|
|
|
|
|
Oil contracts
(Midland basis differential)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
3,022,900
|
|
|
—
|
|
|
Weighted
average price per Bbl
|
$0.26
|
|
|
$—
|
|
|
|
|
|
|
|
Oil contracts
(Argus Houston MEH)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
450,000
|
|
|
—
|
|
|
Weighted
average price per Bbl
|
$46.50
|
|
|
$—
|
|
|
Collar
contracts
|
|
|
|
|
Total volume
(Bbls)
|
409,500
|
|
|
—
|
|
|
Weighted
average price per Bbl
|
|
|
|
|
Ceiling (short
call)
|
$47.00
|
|
|
$—
|
|
|
Floor (long
put)
|
$41.00
|
|
|
$—
|
|
|
|
|
(a)
|
Premiums from the
sale of call options were used to increase the fixed price of
certain simultaneously executed price swaps and three-way
collars.
|
(b)
|
The short call
swaption contracts have exercise expiration dates as follows:
455,000 Bbls expire on March 31, 2021 and 1,825,000 Bbls expire on
December 31, 2021.
|
(c)
|
In January 2021, we
paid approximately $3.1 million to terminate 184,000 Bbls of ICE
Brent swaps. Additionally, in February 2021, we executed offsetting
ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of
approximately $2.9 million which we will pay as the applicable
contracts settle.
|
|
For the Full Year
of
|
|
For the Full Year
of
|
|
Natural gas
contracts (Henry Hub)
|
2021
|
|
2022
|
|
Swap
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
11,123,000
|
|
|
—
|
|
|
Weighted
average price per MMBtu
|
$2.60
|
|
|
$—
|
|
|
Collar contracts
(three-way collars)
|
|
|
|
|
Total volume
(MMBtu)
|
1,350,000
|
|
|
—
|
|
|
Weighted
average price per MMBtu
|
|
|
|
|
Ceiling (short
call)
|
$2.70
|
|
|
$—
|
|
|
Floor (long
put)
|
$2.42
|
|
|
$—
|
|
|
Floor (short
put)
|
$2.00
|
|
|
$—
|
|
|
Collar contracts
(two-way collars)
|
|
|
|
|
Total volume
(MMBtu)
|
9,550,000
|
|
|
1,800,000
|
|
|
Weighted
average price per MMBtu
|
|
|
|
|
Ceiling (short
call)
|
$3.04
|
|
|
$3.88
|
|
|
Floor (long
put)
|
$2.59
|
|
|
$2.78
|
|
|
Short call
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
7,300,000
|
|
(a)
|
—
|
|
|
Weighted
average price per MMBtu
|
$3.09
|
|
|
$—
|
|
|
|
|
|
|
|
Natural gas
contracts (Waha basis differential)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
16,425,000
|
|
|
—
|
|
|
Weighted
average price per MMBtu
|
($0.42)
|
|
|
$—
|
|
|
|
|
(a)
|
Premiums from the
sale of call options were used to increase the fixed price of
certain simultaneously executed price swaps and three-way
collars.
|
|
For the Full Year
of
|
NGL contracts
(OPIS Mont Belvieu Purity Ethane)
|
2021
|
Swap
contracts
|
|
Total volume
(Bbls)
|
1,825,000
|
|
Weighted
average price per Bbl
|
$7.62
|
|
Adjusted Income and Adjusted EBITDA. The
Company reported loss available to common stockholders of
$505.1 million for the three months
ended December 31, 2020, or $12.71 per diluted share, and adjusted income of
$42.8 million, or $1.00 per diluted share. The following tables
reconcile the Company's loss available to common stockholders to
adjusted income, and the Company's net loss to adjusted EBITDA:
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
|
December 31,
2020
|
|
|
(In thousands
except per share data)
|
Loss available to
common stockholders
|
|
($505,071)
|
|
|
($680,384)
|
|
|
($23,543)
|
|
|
($2,533,621)
|
|
(Gain) loss on
derivatives contracts
|
|
125,739
|
|
|
27,038
|
|
|
30,694
|
|
|
27,773
|
|
Gain (loss) on
commodity derivative settlements, net
|
|
(7,938)
|
|
|
(5,540)
|
|
|
(3,353)
|
|
|
95,856
|
|
Non-cash stock-based
compensation expense (benefit)
|
|
2,968
|
|
|
(94)
|
|
|
1,010
|
|
|
2,663
|
|
Impairment of evaluated
oil and gas properties
|
|
585,767
|
|
|
684,956
|
|
|
—
|
|
|
2,547,241
|
|
Merger and integration
expense
|
|
2,120
|
|
|
2,465
|
|
|
68,420
|
|
|
28,482
|
|
Other
expense
|
|
5,328
|
|
|
3,567
|
|
|
—
|
|
|
14,625
|
|
(Gain) loss on
extinguishment of debt
|
|
(170,370)
|
|
|
—
|
|
|
4,881
|
|
|
(170,370)
|
|
Tax effect on
adjustments above(a)
|
|
(114,159)
|
|
|
(149,602)
|
|
|
(21,347)
|
|
|
(534,717)
|
|
Change in valuation
allowance
|
|
118,388
|
|
|
143,152
|
|
|
—
|
|
|
639,185
|
|
Adjusted
income
|
|
$42,772
|
|
|
$25,558
|
|
|
$56,762
|
|
|
$117,117
|
|
Adjusted income per
diluted share
|
|
$1.00
|
|
|
$0.64
|
|
|
$2.28
|
|
|
$2.86
|
|
|
|
|
|
|
|
|
|
|
Basic
WASO(b)
|
|
39,752
|
|
|
39,746
|
|
|
24,822
|
|
|
39,718
|
|
Diluted WASO
(GAAP)(b)
|
|
39,752
|
|
|
39,746
|
|
|
24,822
|
|
|
39,718
|
|
Effective of
potentially dilutive instruments(b)
|
|
2,892
|
|
|
35
|
|
|
21
|
|
|
1,196
|
|
Adjusted Diluted
WASO(b)
|
|
42,644
|
|
|
39,781
|
|
|
24,843
|
|
|
40,914
|
|
|
|
(a)
|
Calculated using the
federal statutory rate of 21%.
|
(b)
|
All share and per
share amounts have been retroactively adjusted for the Company's
1-for-10 reverse stock split effective August 7, 2020.
|
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
|
December 31,
2020
|
|
|
(In
thousands)
|
Net loss
|
|
($505,071)
|
|
|
($680,384)
|
|
|
($23,543)
|
|
|
($2,533,621)
|
|
(Gain) loss on
derivatives contracts
|
|
125,739
|
|
|
27,038
|
|
|
30,694
|
|
|
27,773
|
|
Gain (loss) on
commodity derivative settlements, net
|
|
(7,938)
|
|
|
(5,540)
|
|
|
(3,353)
|
|
|
95,856
|
|
Non-cash stock-based
compensation expense (benefit)
|
|
2,968
|
|
|
(94)
|
|
|
3,390
|
|
|
2,663
|
|
Impairment of
evaluated oil and gas properties
|
|
585,767
|
|
|
684,956
|
|
|
—
|
|
|
2,547,241
|
|
Merger and integration
expense
|
|
2,120
|
|
|
2,465
|
|
|
68,420
|
|
|
28,482
|
|
Other
expense
|
|
5,328
|
|
|
3,567
|
|
|
145
|
|
|
14,625
|
|
Income tax
expense
|
|
6,755
|
|
|
—
|
|
|
5,857
|
|
|
122,054
|
|
Interest expense, net
of capitalized amounts
|
|
26,486
|
|
|
24,683
|
|
|
689
|
|
|
94,329
|
|
Depreciation,
depletion and amortization
|
|
96,037
|
|
|
114,201
|
|
|
63,198
|
|
|
480,631
|
|
(Gain) loss on
extinguishment of debt
|
|
(170,370)
|
|
|
—
|
|
|
4,881
|
|
|
(170,370)
|
|
Adjusted
EBITDA
|
|
$167,821
|
|
|
$170,892
|
|
|
$150,378
|
|
|
$709,663
|
|
Adjusted Free Cash Flow. Adjusted free cash flow for
the three months ended December 31, 2020 was $24.4 million. The following table reconciles the
Company's net cash provided by operating activities to adjusted
EBITDA and adjusted free cash flow:
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
June 30,
2020
|
|
March 31,
2020
|
|
December 31,
2019
|
|
|
(In
thousands)
|
Net cash provided by
operating activities
|
|
$134,578
|
|
|
$135,701
|
|
|
$97,801
|
|
|
$191,695
|
|
|
$137,578
|
|
Changes in working
capital and other
|
|
12,011
|
|
|
14,473
|
|
|
40,078
|
|
|
(32,569)
|
|
|
(55,620)
|
|
Changes in accrued
hedge settlements
|
|
(5,055)
|
|
|
(5,993)
|
|
|
(14,480)
|
|
|
22,513
|
|
|
—
|
|
Cash interest expense,
net
|
|
24,167
|
|
|
24,246
|
|
|
21,944
|
|
|
20,071
|
|
|
—
|
|
Merger and integration
expense
|
|
2,120
|
|
|
2,465
|
|
|
8,067
|
|
|
15,830
|
|
|
68,420
|
|
Adjusted
EBITDA
|
|
$167,821
|
|
|
$170,892
|
|
|
$153,410
|
|
|
$217,540
|
|
|
$150,378
|
|
Less: Operational
capital expenditures (accrual)
|
|
87,488
|
|
|
38,408
|
|
|
85,087
|
|
|
277,640
|
|
|
110,021
|
|
Less: Capitalized
interest
|
|
23,015
|
|
|
20,675
|
|
|
20,924
|
|
|
23,985
|
|
|
21,781
|
|
Less: Interest expense,
net of capitalized amounts
|
|
26,486
|
|
|
24,683
|
|
|
22,682
|
|
|
20,478
|
|
|
689
|
|
Less: Capitalized cash
G&A
|
|
6,465
|
|
|
6,831
|
|
|
6,740
|
|
|
7,371
|
|
|
8,780
|
|
Adjusted free cash
flow
|
|
$24,367
|
|
|
$80,295
|
|
|
$17,977
|
|
|
($111,934)
|
|
|
$9,107
|
|
Adjusted Discretionary Cash Flow. Adjusted
discretionary cash flow for the three months ended
December 31, 2020 was $141.3
million and is reconciled to net cash provided by operating
activities in the following table:
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
|
|
(In
thousands)
|
Net loss
|
|
($505,071)
|
|
|
($680,384)
|
|
|
($23,543)
|
|
Adjustments to
reconcile net loss to cash provided by operating
activities:
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
96,037
|
|
|
114,201
|
|
|
63,198
|
|
Impairment of
evaluated oil and gas properties
|
|
585,767
|
|
|
684,956
|
|
|
—
|
|
Amortization of
non-cash debt related items
|
|
2,319
|
|
|
437
|
|
|
689
|
|
Deferred income tax
expense
|
|
3,308
|
|
|
—
|
|
|
5,857
|
|
(Gain) loss on
derivative contracts
|
|
125,739
|
|
|
27,038
|
|
|
30,694
|
|
Cash (paid) received
for commodity derivative settlements, net
|
|
(2,884)
|
|
|
453
|
|
|
(3,353)
|
|
Non-cash (gain) loss
on early extinguishment of debt
|
|
(170,370)
|
|
|
—
|
|
|
4,881
|
|
Non-cash stock-based
compensation expense (benefit)
|
|
2,968
|
|
|
(94)
|
|
|
3,417
|
|
Merger and integration
expense
|
|
2,120
|
|
|
2,465
|
|
|
68,420
|
|
Other, net
|
|
1,347
|
|
|
2,099
|
|
|
(126)
|
|
Adjusted
discretionary cash flow
|
|
$141,280
|
|
|
$151,171
|
|
|
$150,134
|
|
Changes in working
capital
|
|
(4,582)
|
|
|
(13,005)
|
|
|
55,864
|
|
Merger and integration
expense
|
|
(2,120)
|
|
|
(2,465)
|
|
|
(68,420)
|
|
Net cash provided by
operating activities
|
|
$134,578
|
|
|
$135,701
|
|
|
$137,578
|
|
Adjusted Total Revenue. Adjusted total revenue for
the three months ended December 31, 2020 was $259.0 million and is reconciled to total
operating revenues, which excludes revenue from sales of
commodities purchased from a third-party, in the following
table:
|
|
Three Months
Ended
|
|
|
December 31,
2020
|
|
September 30,
2020
|
|
December 31,
2019
|
|
|
(In
thousands)
|
Operating
Revenues
|
|
|
|
|
|
|
Oil
|
|
$222,733
|
|
|
$231,654
|
|
|
$183,071
|
|
Natural gas
|
|
18,561
|
|
|
15,034
|
|
|
10,949
|
|
Natural gas
liquids
|
|
25,668
|
|
|
23,025
|
|
|
2,075
|
|
Total operating
revenues
|
|
$266,962
|
|
|
$269,713
|
|
|
$196,095
|
|
Impact of settled
derivatives
|
|
(7,938)
|
|
|
(5,540)
|
|
|
(3,353)
|
|
Adjusted total
revenue
|
|
$259,024
|
|
|
$264,173
|
|
|
$192,742
|
|
PV-10. PV-10 as of December 31, 2020 is
reconciled below to the standardized measure of discounted future
net cash flows:
|
|
As of December 31,
2020
|
|
|
(In
millions)
|
Standardized measure
of discounted future net cash flows
|
|
$2,310.4
|
|
Add: present value of
future income taxes discounted at 10% per annum
|
|
$34.6
|
|
Total proved reserves
- PV-10
|
|
$2,345.0
|
|
Total proved
developed reserves - PV-10
|
|
$1,577.3
|
|
Total proved
undeveloped reserves - PV-10
|
|
$767.7
|
|
Callon Petroleum
Company
|
Consolidated
Balance Sheets
|
(in thousands,
except par values and share data)
|
|
|
December
31,
|
|
2020
|
|
2019
|
ASSETS
|
|
|
|
Current
assets:
|
|
|
|
Cash and
cash equivalents
|
$20,236
|
|
|
$13,341
|
|
Accounts
receivable, net
|
133,109
|
|
|
209,463
|
|
Fair
value of derivatives
|
921
|
|
|
26,056
|
|
Other
current assets
|
24,103
|
|
|
19,814
|
|
Total current
assets
|
178,369
|
|
|
268,674
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
Evaluated properties,
net
|
2,355,710
|
|
|
4,682,994
|
|
Unevaluated
properties
|
1,733,250
|
|
|
1,986,124
|
|
Total oil and natural
gas properties, net
|
4,088,960
|
|
|
6,669,118
|
|
Operating lease
right-of-use assets
|
22,526
|
|
|
63,908
|
|
Other property and
equipment, net
|
31,640
|
|
|
35,253
|
|
Deferred tax
asset
|
—
|
|
|
115,720
|
|
Deferred financing
costs
|
23,643
|
|
|
22,233
|
|
Other assets,
net
|
17,730
|
|
|
19,932
|
|
Total
assets
|
$4,362,868
|
|
|
$7,194,838
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts
payable and accrued liabilities
|
$345,365
|
|
|
$490,442
|
|
Operating lease liabilities
|
13,175
|
|
|
42,858
|
|
Fair
value of derivatives
|
97,060
|
|
|
71,197
|
|
Other
current liabilities
|
41,508
|
|
|
47,750
|
|
Total current
liabilities
|
497,108
|
|
|
652,247
|
|
Long-term
debt
|
2,969,264
|
|
|
3,186,109
|
|
Operating lease
liabilities
|
27,576
|
|
|
37,088
|
|
Asset retirement
obligations
|
57,209
|
|
|
48,860
|
|
Fair value of
derivatives
|
88,046
|
|
|
32,695
|
|
Other long-term
liabilities
|
12,663
|
|
|
14,531
|
|
Total
liabilities
|
3,651,866
|
|
|
3,971,530
|
|
Commitments and
contingencies
|
|
|
|
Stockholders'
equity:
|
|
|
|
Common
stock, $0.01 par value, 52,500,000 shares authorized, 39,758,817
and 39,659,001 shares outstanding,
respectively (a)
|
398
|
|
|
3,966
|
|
Capital
in excess of par
|
3,222,959
|
|
|
3,198,076
|
|
Retained
earnings (Accumulated deficit)
|
(2,512,355)
|
|
|
21,266
|
|
Total stockholders'
equity
|
711,002
|
|
|
3,223,308
|
|
Total liabilities and
stockholders' equity
|
$4,362,868
|
|
|
$7,194,838
|
|
|
|
(a)
|
All share amounts
(except par value) have been retroactively adjusted for the
Company's 1-for-10 reverse stock split effective August 7,
2020.
|
Callon Petroleum
Company
|
Consolidated
Statements of Operations
|
(in thousands,
except per share data)
|
|
|
Three Months Ended
December 31,
|
|
For the Year Ended
December 31,
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Operating
Revenues:
|
|
|
|
|
|
|
|
Oil
|
$222,733
|
|
|
$183,071
|
|
|
$850,667
|
|
|
$633,107
|
|
Natural gas
|
18,561
|
|
|
10,949
|
|
|
51,866
|
|
|
36,390
|
|
Natural gas
liquids
|
25,668
|
|
|
2,075
|
|
|
81,295
|
|
|
2,075
|
|
Sales of purchased oil
and gas
|
29,006
|
|
|
—
|
|
|
49,319
|
|
|
—
|
|
Total operating
revenues
|
295,968
|
|
|
196,095
|
|
|
1,033,147
|
|
|
671,572
|
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
Lease
operating
|
45,010
|
|
|
25,316
|
|
|
194,101
|
|
|
91,827
|
|
Production and ad
valorem taxes
|
16,487
|
|
|
8,841
|
|
|
62,638
|
|
|
42,651
|
|
Gathering,
transportation and processing
|
20,694
|
|
|
—
|
|
|
77,309
|
|
|
—
|
|
Cost of purchased oil
and gas
|
30,484
|
|
|
—
|
|
|
51,766
|
|
|
—
|
|
Depreciation,
depletion and amortization
|
96,037
|
|
|
61,367
|
|
|
480,631
|
|
|
240,642
|
|
General and
administrative
|
10,614
|
|
|
13,626
|
|
|
37,187
|
|
|
45,331
|
|
Impairment of
evaluated oil and gas properties
|
585,767
|
|
|
—
|
|
|
2,547,241
|
|
|
—
|
|
Merger and integration
expenses
|
2,120
|
|
|
68,420
|
|
|
28,482
|
|
|
74,363
|
|
Other
operating
|
2,084
|
|
|
145
|
|
|
10,644
|
|
|
4,100
|
|
Total operating
expenses
|
809,297
|
|
|
177,715
|
|
|
3,489,999
|
|
|
498,914
|
|
Income (Loss) From
Operations
|
(513,329)
|
|
|
18,380
|
|
|
(2,456,852)
|
|
|
172,658
|
|
|
|
|
|
|
|
|
|
Other (Income)
Expenses:
|
|
|
|
|
|
|
|
Interest expense, net
of capitalized amounts
|
26,486
|
|
|
689
|
|
|
94,329
|
|
|
2,907
|
|
(Gain) loss on
derivative contracts
|
125,739
|
|
|
30,694
|
|
|
27,773
|
|
|
62,109
|
|
(Gain) loss on
extinguishment of debt
|
(170,370)
|
|
|
4,881
|
|
|
(170,370)
|
|
|
4,881
|
|
Other (income)
expense
|
3,132
|
|
|
(198)
|
|
|
2,983
|
|
|
(468)
|
|
Total other (income)
expense
|
(15,013)
|
|
|
36,066
|
|
|
(45,285)
|
|
|
69,429
|
|
|
|
|
|
|
|
|
|
Income (Loss)
Before Income Taxes
|
(498,316)
|
|
|
(17,686)
|
|
|
(2,411,567)
|
|
|
103,229
|
|
Income tax
expense
|
(6,755)
|
|
|
(5,857)
|
|
|
(122,054)
|
|
|
(35,301)
|
|
Net Income
(Loss)
|
($505,071)
|
|
|
($23,543)
|
|
|
($2,533,621)
|
|
|
$67,928
|
|
Preferred stock
dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,997)
|
|
Loss on redemption of
preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,304)
|
|
Income (Loss)
Available to Common Stockholders
|
($505,071)
|
|
|
($23,543)
|
|
|
($2,533,621)
|
|
|
$55,627
|
|
|
|
|
|
|
|
|
|
Income (Loss)
Available to Common Stockholders Per Common Share
(a):
|
|
|
|
|
|
|
|
Basic
|
($12.71)
|
|
|
($0.95)
|
|
|
($63.79)
|
|
|
$2.39
|
|
Diluted
|
($12.71)
|
|
|
($0.95)
|
|
|
($63.79)
|
|
|
$2.38
|
|
|
|
|
|
|
|
|
|
Weighted Average
Common Shares Outstanding (a):
|
|
|
|
|
|
|
|
Basic
|
39,752
|
|
|
24,822
|
|
|
39,718
|
|
|
23,313
|
|
Diluted
|
39,752
|
|
|
24,822
|
|
|
39,718
|
|
|
23,340
|
|
|
|
(a)
|
All share and per
share amounts have been retroactively adjusted for the Company's
1-for-10 reverse stock split effective August 7, 2020.
|
Callon Petroleum
Company
|
Consolidated
Statements of Cash Flows
|
(in
thousands)
|
|
|
Three Months
Ended
December 31,
|
|
For the Year
Ended
December 31,
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
($505,071)
|
|
|
($23,543)
|
|
|
($2,533,621)
|
|
|
$67,928
|
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
96,037
|
|
|
63,198
|
|
|
480,631
|
|
|
245,936
|
|
Impairment of
evaluated oil and gas properties
|
585,767
|
|
|
—
|
|
|
2,547,241
|
|
|
—
|
|
Amortization
of non-cash debt related items
|
2,319
|
|
|
689
|
|
|
3,901
|
|
|
2,907
|
|
Deferred
income tax expense
|
3,308
|
|
|
5,857
|
|
|
118,607
|
|
|
35,301
|
|
(Gain) loss on
derivative contracts
|
125,739
|
|
|
30,694
|
|
|
27,773
|
|
|
62,109
|
|
Cash received
(paid) for commodity derivative settlements, net
|
(2,884)
|
|
|
(3,353)
|
|
|
98,870
|
|
|
(3,789)
|
|
(Gain) loss on
early extinguishment of debt
|
(170,370)
|
|
|
4,881
|
|
|
(170,370)
|
|
|
4,881
|
|
Non-cash
expense related to equity share-based awards
|
471
|
|
|
1,899
|
|
|
6,773
|
|
|
9,767
|
|
Change in the
fair value of liability share-based awards
|
2,497
|
|
|
1,518
|
|
|
(4,110)
|
|
|
1,624
|
|
Payments for
cash-settled restricted stock unit awards
|
—
|
|
|
—
|
|
|
(770)
|
|
|
(1,425)
|
|
Other,
net
|
1,347
|
|
|
(126)
|
|
|
7,857
|
|
|
(90)
|
|
Changes in
current assets and liabilities:
|
|
|
|
|
|
|
|
Accounts receivable
|
(20,340)
|
|
|
(52,671)
|
|
|
75,770
|
|
|
(35,071)
|
|
Other current assets
|
6
|
|
|
1,006
|
|
|
(6,550)
|
|
|
(4,166)
|
|
Accounts payable and accrued liabilities
|
15,752
|
|
|
96,753
|
|
|
(92,227)
|
|
|
82,290
|
|
Other
|
—
|
|
|
10,776
|
|
|
—
|
|
|
8,114
|
|
Net cash provided by operating activities
|
134,578
|
|
|
137,578
|
|
|
559,775
|
|
|
476,316
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
(109,408)
|
|
|
(137,115)
|
|
|
(677,154)
|
|
|
(640,540)
|
|
Acquisitions
|
—
|
|
|
(1,478)
|
|
|
—
|
|
|
(42,266)
|
|
Proceeds from sales
of assets
|
29,152
|
|
|
14,465
|
|
|
178,970
|
|
|
294,417
|
|
Cash paid for
settlements of contingent consideration arrangements,
net
|
—
|
|
|
—
|
|
|
(40,000)
|
|
|
—
|
|
Other, net
|
40
|
|
|
—
|
|
|
8,301
|
|
|
—
|
|
Net cash used in investing activities
|
(80,216)
|
|
|
(124,128)
|
|
|
(529,883)
|
|
|
(388,389)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
Borrowings on Credit
Facility
|
265,500
|
|
|
1,874,900
|
|
|
5,353,000
|
|
|
2,455,900
|
|
Payments on Credit
Facility
|
(305,500)
|
|
|
(314,500)
|
|
|
(5,653,000)
|
|
|
(895,500)
|
|
Payment to terminate
Prior Credit Facility
|
—
|
|
|
(475,400)
|
|
|
—
|
|
|
(475,400)
|
|
Repayment of
Carrizo's senior secured revolving credit facility
|
—
|
|
|
(853,549)
|
|
|
—
|
|
|
(853,549)
|
|
Repayment of
Carrizo's preferred stock
|
—
|
|
|
(220,399)
|
|
|
—
|
|
|
(220,399)
|
|
Issuance of 9.00%
Second Lien Senior Secured Notes due 2025
|
—
|
|
|
—
|
|
|
300,000
|
|
|
—
|
|
Discount on the
issuance of 9.00% Second Lien Senior Secured Notes due
2025
|
—
|
|
|
—
|
|
|
(35,270)
|
|
|
—
|
|
Issuance of September
2020 Warrants
|
—
|
|
|
—
|
|
|
23,909
|
|
|
—
|
|
Payment of preferred
stock dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,997)
|
|
Payment of deferred
financing costs and debt exchange costs
|
(4,499)
|
|
|
(22,449)
|
|
|
(10,811)
|
|
|
(22,480)
|
|
Tax withholdings
related to restricted stock units
|
(14)
|
|
|
(21)
|
|
|
(509)
|
|
|
(2,195)
|
|
Redemption of
preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(73,017)
|
|
Other, net
|
(113)
|
|
|
—
|
|
|
(316)
|
|
|
—
|
|
Net cash used in financing activities
|
(44,626)
|
|
|
(11,418)
|
|
|
(22,997)
|
|
|
(90,637)
|
|
Net change in cash
and cash equivalents
|
9,736
|
|
|
2,032
|
|
|
6,895
|
|
|
(2,710)
|
|
Balance,
beginning of period
|
10,500
|
|
|
11,309
|
|
|
13,341
|
|
|
16,051
|
|
Balance, end
of period
|
$20,236
|
|
|
$13,341
|
|
|
$20,236
|
|
|
$13,341
|
|
Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures such
as "adjusted free cash flow," "adjusted discretionary cash
flow," "adjusted G&A," "full cash G&A," "adjusted income,"
"adjusted income per diluted share," "adjusted EBITDA", "adjusted
total revenue", and "PV-10." These measures, detailed below,
are provided in addition to, and not as an alternative for, and
should be read in conjunction with, the information contained in
our financial statements prepared in accordance with GAAP
(including the notes), included in our filings with the U.S.
Securities and Exchange Commission (the "SEC") and posted on our
website.
- Adjusted free cash flow is a supplemental non-GAAP measure that
is defined by the Company as adjusted EBITDA less operational
capital, capitalized interest, net interest expense and capitalized
cash G&A (which excludes capitalized expense related to
share-based awards). We believe adjusted free cash flow is a
comparable metric against other companies in the industry and is a
widely accepted financial indicator of an oil and natural gas
company's ability to generate cash for the use of internally
funding their capital development program and to service or incur
debt. Adjusted free cash flow is not a measure of a company's
financial performance under GAAP and should not be considered as an
alternative to net cash provided by operating activities, or as a
measure of liquidity, or as an alternative to net income
(loss).
- Adjusted discretionary cash flow is a supplemental non-GAAP
measure that Callon believes is a comparable metric against other
companies in the industry and is a widely accepted financial
indicator of an oil and natural gas company's ability to generate
cash for the use of internally funding their capital development
program and to service or incur debt. Adjusted discretionary cash
flow is defined by Callon as net cash provided by operating
activities before changes in working capital and merger and
integration expenses. Callon has included this information because
changes in operating assets and liabilities relate to the timing of
cash receipts and disbursements, which the Company may not control
and the cash flow effect may not be reflected the period in which
the operating activities occurred. Adjusted discretionary cash flow
is not a measure of a company's financial performance under GAAP
and should not be considered as an alternative to net cash provided
by operating activities, or as a measure of liquidity, or as an
alternative to net income (loss).
- Adjusted G&A is a supplemental non-GAAP financial measure
that excludes certain non-recurring expenses and non-cash valuation
adjustments related to incentive compensation plans. Callon
believes that the non-GAAP measure of adjusted G&A is useful to
investors because it provides a meaningful measure of our recurring
G&A expense and provides for greater comparability
period-over-period. See the reconciliation provided above for
further details.
- Full cash G&A is a supplemental non-GAAP financial measure
that Callon defines as adjusted G&A – cash component plus
capitalized G&A excluding capitalized expense related to
share-based awards. Callon believes that the non-GAAP measure of
full cash G&A is useful because it provides users with a
meaningful measure of our total recurring cash G&A costs,
whether expensed or capitalized, and provides for greater
comparability on a period-over-period basis. See the reconciliation
provided above for further details.
- Adjusted income and adjusted income per diluted share are
supplemental non-GAAP measures that Callon believes are useful to
investors because they provide readers with a meaningful measure of
our profitability before recording certain items whose timing or
amount cannot be reasonably determined. These measures exclude the
net of tax effects of these items and non-cash valuation
adjustments, which are detailed in the reconciliation provided.
Adjusted income and adjusted income per diluted share are not
measures of financial performance under GAAP. Accordingly, it
should not be considered as a substitute for net income (loss),
operating income (loss), or other income data prepared in
accordance with GAAP. However, the Company believes that adjusted
income and adjusted income per diluted share provide additional
information with respect to our performance. Because adjusted
income and adjusted income per diluted share exclude some, but not
all, items that affect net income (loss) and may vary among
companies, the adjusted income and adjusted income per diluted
share presented above may not be comparable to similarly titled
measures of other companies.
- Adjusted diluted weighted average common shares outstanding
("Adjusted Diluted WASO") is a non-GAAP financial measure which
includes the effect of potentially dilutive instruments that, under
certain circumstances described below, are excluded from diluted
weighted average common shares outstanding ("Diluted WASO"), the
most directly comparable GAAP financial measure. When a loss
available to common stockholders exists, all potentially dilutive
instruments are anti-dilutive to the loss available to common
stockholders per common share and therefore excluded from the
computation of Diluted WASO. The effect of potentially dilutive
instruments are included in the computation of Adjusted Diluted
WASO for purposes of computing adjusted income per diluted
share.
- Callon calculates adjusted earnings before interest, income
taxes, depreciation, depletion and amortization ("Adjusted EBITDA")
as net income (loss) before interest expense, income tax expense
(benefit), depreciation, depletion and amortization, (gains) losses
on derivative instruments excluding net settled derivative
instruments, impairment of evaluated oil and gas properties,
non-cash stock-based compensation expense, merger and integration
expense, (gain) loss on extinguishment of debt, and other operating
expenses. Adjusted EBITDA is not a measure of financial performance
under GAAP. Accordingly, it should not be considered as a
substitute for net income (loss), operating income (loss), cash
flow provided by operating activities or other income or cash flow
data prepared in accordance with GAAP. However, the Company
believes that adjusted EBITDA provides additional information with
respect to our performance or ability to meet our future debt
service, capital expenditures and working capital requirements.
Because adjusted EBITDA excludes some, but not all, items that
affect net income (loss) and may vary among companies, the adjusted
EBITDA presented above may not be comparable to similarly titled
measures of other companies.
- Callon believes that the non-GAAP measure of adjusted total
revenue is useful to investors because it provides readers with a
revenue value more comparable to other companies who engage in
price risk management activities through the use of commodity
derivative instruments and reflects the results of derivative
settlements with expected cash flow impacts within total revenues.
See the reconciliation provided above for further details.
- Callon believes that the presentation of pre-tax PV-10 value is
relevant and useful to its investors because it presents the
discounted future net cash flows attributable to reserves prior to
taking into account future corporate income taxes and the Company's
current tax structure. The Company further believes investors and
creditors use pre-tax PV-10 values as a basis for comparison of the
relative size and value of its reserves as compared with other
companies. The GAAP financial measure most directly comparable to
pre-tax PV-10 is the standardized measure of discounted future net
cash flows. Pre-tax PV-10 is calculated using the standardized
measure of discounted future net cash flows before deducting future
income taxes, discounted at 10 percent.
Earnings Call Information
The Company will host a conference call on Thursday, February 25, 2021, to discuss fourth
quarter 2020 financial and operating results, 2021 outlook, and the
durability of our business under various commodity price
scenarios.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Thursday, February
25, 2021, at 8:00 a.m. Central Time (9:00 a.m. Eastern
Time)
|
Webcast:
|
Select "News and
Events" under the "Investors" section of the Company's website:
www.callon.com.
|
An archive of the conference call webcast will also be available
at www.callon.com under the "Investors" section of the website.
About Callon Petroleum
Callon Petroleum Company is an independent oil and natural gas
company focused on the acquisition, exploration and development of
high-quality assets in the leading oil plays of South and
West Texas.
Cautionary Statement Regarding Forward Looking
Statements
This news release contains 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 include all statements regarding wells anticipated to be
drilled and placed on production; future levels of development
activity and associated production, capital expenditures and cash
flow expectations; the Company's 2021 production expense guidance
and capital expenditure guidance; estimated reserve quantities and
the present value thereof; and the implementation of the Company's
business plans and strategy, as well as statements including the
words "believe," "expect," "plans", "may", "will", "should",
"could" and words of similar meaning. These statements reflect the
Company's current views with respect to future events and financial
performance based on management's experience and perception of
historical trends, current conditions, anticipated future
developments and other factors believed to be appropriate. No
assurances can be given, however, that these events will occur or
that these projections will be achieved, and actual results could
differ materially from those projected as a result of certain
factors. Any forward-looking statement speaks only as of the date
on which such statement is made and the Company undertakes no
obligation to correct or update any forward-looking statement,
whether as a result of new information, future events or otherwise,
except as required by applicable law. Some of the factors which
could affect our future results and could cause results to differ
materially from those expressed in our forward-looking statements
include the volatility of oil and natural gas prices; changes in
the supply of and demand for oil and natural gas, including as a
result of the COVID-19 pandemic and various governmental actions
taken to mitigate its impact or actions by, or disputes among,
members of OPEC and other oil and natural gas producing countries,
such as Russia, with respect to
production levels or other matters related to the price of oil; our
ability to drill and complete wells, operational, regulatory and
environment risks; the cost and availability of equipment and
labor; our ability to finance our activities; and other risks
more fully discussed in our filings with the SEC, including our
most recent Annual Reports on Form 10-K and subsequent Quarterly
Reports on Form 10-Q, available on our website or the SEC's website
at www.sec.gov.
Contact information
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5200
1)
|
See "Non-GAAP
Financial Measures" included within this release for related
disclosures.
|
2)
|
All references to
2019 pro forma figures assume full year Callon and Carrizo combined
financials
|
3)
|
Callon defines
"reinvestment rate" as (Accrued Operational Capital Expenditures) /
(Adjusted Discretionary Cash Flow - Capitalized
Expenses)
|
4)
|
Management's internal
estimate of PV-10 value at flat forward prices set forth above is
provided to illustrate reserve sensitivities to expectations of
commodity prices and do not comply with SEC pricing assumptions.
Actual future prices may vary significantly from the flat forward
prices used in management's internal estimate of PV-10; therefore,
actual revenue and value generated may be more or less than the
PV-10 estimate.
|
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SOURCE Callon Petroleum Company