HOUSTON, Feb. 26, 2020 /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, 2019. All financial and operating results
presented include Carrizo Oil & Gas, Inc. results from
December 21 to December 31, 2019
unless otherwise noted.
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.
2019 Highlights
- Full-year 2019 production of 41.3 Mboe/d (77% oil), an increase
of 26% over 2018 volumes
- Year-end proved reserves of 540.0 MMboe (64% oil), a
year-over-year increase of 126%
- Realized income available to common stockholders of
$55.6 million, or $0.24 per diluted share, and adjusted net
income(i) of $176.3
million or $0.76 per diluted
share
- Generated an operating margin(i) of $35.60 per Boe reflecting our high level of oil
volumes and lease operating expense reductions
- Generated Adjusted EBITDA(i) of $502.1 million
- Completed the acquisition of Carrizo Oil & Gas, creating an
oil-weighted growth company with premier positions in the Permian
Basin and Eagle Ford Shale
- Divested approximately $300
million in non-core assets as part of ongoing initiatives to
enhance returns on capital employed and strengthen our financial
position through absolute debt reduction
- Redeemed approximately $270
million in preferred securities, eliminating $25 million in annual future dividend
payments
Fourth Quarter 2019 Highlights
- Fourth quarter 2019 production of 46.6 Mboe/d (75% oil), an
increase of 14% over fourth quarter 2018 volumes and a sequential
increase of 23%
- Realized loss available to common stockholders of $23.5 million, or ($0.09) per diluted share, and adjusted net
income(i) of $56.8 million
or $0.23 per diluted share
- Generated $137.6 million of cash
from operating activities, exceeding cash used in investing
activities for operational capital additions of $105.8 million
- Sustained strong operating margins of $37.74 per Boe
- Built an inventory of drilled, uncompleted wells to support
larger scale development in the Delaware Basin
Joe Gatto, President and Chief
Executive Officer commented, "2019 was a transformational year and
a significant step forward for Callon. We executed multiple
strategic initiatives while delivering on our capital development
plan with improved efficiency and lower costs. The acquisition of
Carrizo has transformed Callon into a more robust entity with the
capacity to execute a model of scaled development to drive lower
free cash flow break-even costs and sustain growth in a low oil
price environment. We generated free cash flow on both a
stand-alone and pro forma basis in the fourth quarter, setting the
stage for us to deliver free cash flow generation at $50/Bbl in 2020. Our transition to larger
projects featuring multi-zone co-development across the the Permian
asset base is reflected in our 2020 capital program. Given the
capital synergies and overall efficiency we will capture from this
development model, our 2020 capital program is more than
$100 million below our pro forma 2019
capital spending levels."
He continued, "I am very pleased by the progress that the
organization has made in both integrating the combined activity
plans ahead of schedule and driving our operational capital synergy
targets higher than initially estimated. We now anticipate total
year-one synergies from corporate cost and operational capital
items to be over $80 million,
excluding the impact of improved uptime from a program with less
offsetting completion downtime. We remain steadfast in our
long-term value focus in our life of field development philosophy,
employing resource development concepts and a pace of activity that
will keep us on a path to sustainable free cash flow growth from
repeatable investments in our high quality asset base."
Environmental, Social, and Governance ("ESG") Updates
Callon today also announced the Company's achievement of its
best safety performance on record during 2019, reflecting the
Company's dedication to a culture of responsibility. Furthermore,
the Company's environmental sustainability initiatives resulted in
a 40% year-over-year reduction in flaring intensity, as defined by
the Texas Railroad Commission, and a two-fold increase in
company-wide recycled water volumes during the fiscal year.
Callon continues to evolve its executive compensation program to
align with shareholder priorities. The Company has included an
absolute total shareholder return ("TSR") modifier to the
performance share program that links executive pay to the absolute
returns realized by the Company's shareholders. Under the plan,
payouts for the performance period will be reduced if annualized
TSR is below the threshold of 5%, reflect a multiplier of 100% upon
achieving an annualized TSR of 5% - 10%, and will include higher
multipliers upon achieving an annualized TSR of greater than 10%.
Additional detail will be available in the Company's upcoming
proxy.
Operations Update and Outlook
At December 31, 2019, Callon had 1,409 gross (1,242.3 net)
horizontal wells producing from established flow units in the
Permian Basin and Eagle Ford Shale. Net daily production for the
three months ended December 31, 2019 grew 14% to 46.6 Mboe/d
(75% oil) as compared to the same period of 2018. Full year
production for 2019 averaged 41.3 Mboe/d (77% oil) reflecting
growth of 26% over 2018 volumes.
For the three months ended December 31, 2019, Callon
drilled 11 gross (10.2 net) horizontal wells and placed a combined
14 gross (9.0 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 B in the Delaware
Basin.
Legacy Carrizo activity in the fourth quarter was primarily
focused on the building of an inventory of drilled uncompleted
wells in the Eagle Ford Shale and Delaware Basin to provide the flexibility
required for larger scale development in early 2020. During the
quarter, legacy Carrizo drilled 28 gross (26.6 net) wells and
placed 4 gross (3.2 net) wells on production near the beginning of
the quarter.
Callon entered 2020 with an inventory of over 60 drilled
uncompleted wells to support a new, integrated model of scaled
development and deployed four completion crews to both the
Delaware Basin and Eagle Ford
Shale to turn several large projects to production in the first and
second quarters. In mid-February, a 16-well project in the Eagle
Ford and a five-well, co-development project in the Delaware were brought online as the new
development model starts to progress for 2020. Additional large
scale projects including two Eagle Ford projects totaling roughly
45 wells, multiple Delaware projects in both Eastern Reeves County and Ward County, and select Midland Basin projects
will be completed and placed on production throughout the remainder
of the first and second quarter. The Company is currently operating
nine drilling rigs and four dedicated completion crews with plans
to operate eight to nine drilling rigs and an average of three
completion crews during this year.
2020 Capital Expenditures Budget
Callon has established an operational capital expenditure budget
of $975 million for 2020 with
approximately 70% of drilling, completion and equipment
expenditures ("DC&E") allocated to the Permian Basin.
Development capital related to drilling, completion and equipping
new wells is expected to compose approximately 85% to 90% of the
spending with facilities and other items accounting for the
remainder. The operational program in the Permian Basin will focus
on co-development projects designed to optimize production and
resource recovery from multiple zones. The Company also plans to
continue large scale, multi-pad development in the Eagle Ford
Shale, providing a balance of capital intensity and cycle times
relative to the Delaware Basin
program.
The 2020 plan implies a material improvement in capital
efficiency relative to the 2019 pro forma spend of the combined
companies and to the initial 2020 targeted operational capital
spend of approximately $1.1 billion.
Accelerated integration of the combined development programs,
combined with the identification of additional sources of cost
reductions and best practices as part of large scale development in
the Delaware Basin, has resulted
in a planned DC&E cost of under $1,000 per lateral foot in the Delaware Basin, surpassing initial synergy
estimates.
Callon expects to drill approximately 165 gross operated wells
and place 160 gross operated wells on production during 2020.
Additional 2020 capital program highlights include:
- Initial 2020 full year production guidance (on a three-stream
basis) is 115.0 to 120.0 MBoe/d with an oil cut of approximately
66%
- DC&E expenditures for the year are weighted approximately
60% to the first half of the year and 30% to the first quarter
- Average lateral lengths for the year are projected between
~7,900 feet and ~9,000 feet across all three asset areas
- Working interest will vary between 80% and 95% dependent upon
project and asset area
- First quarter and second quarter completions activity will
primarily be composed of Eagle Ford and Delaware wells
- First quarter production guidance is 95.0 to 100.0 MBoe/d with
an oil cut of 65%
- Second quarter production growth is expected to be in excess of
15%
- Gross wells placed on production in the second quarter are
expected to be the highest of any period during the year
- Projected oil volumes are more than 60% hedged for the entire
year and more than 70% hedged for the first quarter
- The inventory of drilled uncompleted wells completed early in
the year will be replenished throughout the year with an increased
weighting to the Permian Basin providing ongoing flexibility within
the larger development model in 2021 and is projected to be more
than 60 wells by year-end 2020
The remainder of our full year 2020 outlook is provided later in
this release under the section titled "2020 Guidance."
Capital Expenditures
For the twelve months ended December 31, 2019, Callon
incurred $515.1 million in
operational capital expenditures on an accrual basis as compared to
$583.4 million in 2018. For the three
months ended December 31, 2019, the Company incurred
$110.0 million in operational capital
expenditures on an accrual basis, which represented a $6.4 million decrease from the third quarter.
Total capital expenditures, inclusive of capitalized expenses, are
detailed below on an accrual and cash basis:
|
|
Three Months Ended
December 31, 2019
|
|
|
Operational
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
|
Capital
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
|
|
(In
thousands)
|
Cash basis
(b)
|
|
$105,846
|
|
|
$23,614
|
|
|
$7,655
|
|
|
$137,115
|
|
Timing adjustments
(c)
|
|
4,175
|
|
|
(1,833)
|
|
|
—
|
|
|
2,342
|
|
Non-cash
items
|
|
—
|
|
|
—
|
|
|
1,125
|
|
|
1,125
|
|
Accrual
(GAAP) basis (d)
|
|
$110,021
|
|
|
$21,781
|
|
|
$8,780
|
|
|
$140,582
|
|
|
|
(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.
|
(d)
|
Accrual basis capital
as shown includes the impact of legacy Carrizo expenditures after
December 20th close date.
|
Operating and Financial Results
The following table presents summary information for the periods
indicated:
|
|
Three Months
Ended,
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
Net
production
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
3,234
|
|
|
2,725
|
|
|
3,076
|
|
Natural gas
(MMcf)
|
|
5,530
|
|
|
4,538
|
|
|
4,225
|
|
NGLs
(MBbls)
|
|
135
|
|
|
—
|
|
|
—
|
|
Total barrels of oil
equivalent (MBoe)
|
|
4,291
|
|
|
3,481
|
|
|
3,780
|
|
Total daily
production (Boe/d)
|
|
46,641
|
|
|
37,837
|
|
|
41,087
|
|
Oil as % of total
daily production
|
|
75
|
%
|
|
78
|
%
|
|
81
|
%
|
Average realized
sales price
(excluding impact of settled
derivatives)
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
$56.61
|
|
|
$54.39
|
|
|
$48.89
|
|
Natural gas (per
Mcf)
|
|
$1.98
|
|
|
$1.58
|
|
|
$2.72
|
|
NGLs (per
Bbl)
|
|
$15.37
|
|
|
$—
|
|
|
$—
|
|
Total (per
Boe)
|
|
$45.70
|
|
|
$44.64
|
|
|
$42.83
|
|
Average realized
sales price
(including impact of settled
derivatives)
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
$55.33
|
|
|
$54.01
|
|
|
$48.52
|
|
Natural gas (per
Mcf)
|
|
$2.12
|
|
|
$2.03
|
|
|
$2.62
|
|
NGLs (per
Bbl)
|
|
$15.37
|
|
|
$—
|
|
|
$—
|
|
Total (per
Boe)
|
|
$44.92
|
|
|
$44.93
|
|
|
$42.41
|
|
Revenues (in
thousands)
|
|
|
|
|
|
|
Oil
|
|
$183,071
|
|
|
$148,210
|
|
|
$150,398
|
|
Natural
gas
|
|
10,949
|
|
|
7,168
|
|
|
11,497
|
|
NGLs
|
|
2,075
|
|
|
—
|
|
|
—
|
|
Total
revenues
|
|
$196,095
|
|
|
$155,378
|
|
|
$161,895
|
|
Additional per Boe
data
|
|
|
|
|
|
|
Sales price
(a)
|
|
$45.70
|
|
|
$44.64
|
|
|
$42.83
|
|
Lease operating
expense
|
|
5.90
|
|
|
5.65
|
|
|
6.47
|
|
Production
taxes
|
|
2.06
|
|
|
3.41
|
|
|
2.51
|
|
Operating
margin
|
|
$37.74
|
|
|
$35.58
|
|
|
$33.85
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and amortization
|
|
$14.30
|
|
|
$16.09
|
|
|
$15.74
|
|
Adjusted G&A
(b)
|
|
|
|
|
|
|
Cash component
(c)
|
|
$2.41
|
|
|
$2.52
|
|
|
$2.03
|
|
Non-cash
component
|
|
$0.53
|
|
|
$0.44
|
|
|
$0.50
|
|
|
|
(a)
|
Excludes the impact
of settled derivatives.
|
(b)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. Adjusted
G&A is a non-GAAP financial measure; see the reconciliation
provided within this press release for a reconciliation of G&A
expense on a GAAP basis to Adjusted G&A expense.
|
(c)
|
Excludes the
amortization of equity-settled share-based incentive awards and
corporate depreciation and amortization.
|
Total Revenue. For the quarter ended
December 31, 2019, Callon reported total revenue of
$196.1 million and total revenue
including the gain or loss from the settlement of derivative
contracts ("Adjusted Total Revenue"(i)) of $192.7 million, reflecting the impact of a
$3.4 million loss from the settlement
of derivative contracts. Average daily production for the quarter
was 46.6 Mboe/d compared to average daily production of 37.8 Mboe/d
in the third quarter of 2019. Average realized prices, including
and excluding the effects of hedging, are detailed above.
Hedging impacts. For the quarter ended December 31,
2019, Callon recognized the following hedging-related items:
|
|
Three Months Ended
December 31, 2019
|
|
|
In
Thousands
|
|
Per
Unit
|
Oil
derivatives
|
|
|
|
|
Net loss on
settlements
|
|
($4,140)
|
|
|
($1.28)
|
|
Net loss on fair
value adjustments
|
|
(34,375)
|
|
|
|
Total loss on oil
derivatives
|
|
($38,515)
|
|
|
|
Natural gas
derivatives
|
|
|
|
|
Net gain on
settlements
|
|
$787
|
|
|
$0.14
|
|
Net gain on fair
value adjustments
|
|
3,796
|
|
|
|
Total gain on natural
gas derivatives
|
|
$4,583
|
|
|
|
Total oil &
natural gas derivatives
|
|
|
|
|
Net loss on
settlements
|
|
($3,353)
|
|
|
($0.78)
|
|
Net loss on fair
value adjustments
|
|
(30,579)
|
|
|
|
Total loss on oil
& natural gas derivatives
|
|
($33,932)
|
|
|
|
Lease Operating Expenses, including workover
("LOE"). LOE per Boe for the three months ended
December 31, 2019 was $5.90 per
Boe, compared to LOE of $5.65 per Boe
in the third quarter of 2019. The slight increase is primarily from
an increase in costs associated with recently acquired assets that
reflect a higher historical operating cost.
Production Taxes, including ad valorem taxes. Production
taxes were $2.06 per Boe for the
three months ended December 31, 2019, representing
approximately 5% of total revenue before the impact of derivative
settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
December 31, 2019 was $14.30 per
Boe compared to $16.09 per Boe in the
third quarter of 2019. The decrease was primarily attributed to the
inclusion of the reserves acquired from Carrizo which lowered our
depletion rate for the quarter.
General and Administrative ("G&A"). G&A was
$13.6 million, or $3.18 per Boe, and G&A, excluding certain
non-cash incentive share-based compensation valuation adjustments,
("Adjusted G&A"(i)) was $12.6
million, or $2.94 per Boe, for
the three months ended December 31, 2019 compared to
$10.3 million, or $2.96 per Boe, for the third quarter of 2019. The
cash component of Adjusted G&A was $10.3
million, or $2.41 per Boe, for
the three months ended December 31, 2019 compared to
$8.8 million, or $2.52 per Boe, for the third quarter of 2019.
For the three months ended December 31, 2019, G&A and
Adjusted G&A, which excludes the amortization of
equity-settled, share-based incentive awards and corporate
depreciation and amortization, are calculated as follows (in
thousands):
|
|
Three Months
Ended
December 31, 2019
|
Total G&A
expense
|
|
$13,626
|
|
Change in the fair
value of liability share-based awards (non-cash)
|
|
(1,010)
|
|
Adjusted G&A –
total
|
|
12,616
|
|
Restricted stock
share-based compensation (non-cash)
|
|
(1,855)
|
|
Corporate
depreciation & amortization (non-cash)
|
|
(439)
|
|
Adjusted G&A –
cash component
|
|
$10,322
|
|
Income tax expense. Callon provides for income taxes at a
statutory rate of 21% adjusted for permanent differences
expected to be realized. The Company recorded income tax expense of
$5.9 million for the three months
ended December 31, 2019, compared to income tax expense of
$17.9 million for the three months
ended September 30, 2019. The change
in income tax expense is based upon activity during the respective
periods.
Proved Reserves
DeGolyer and MacNaughton and Ryder Scott Company, L.P. prepared
estimates of Callon and legacy Carrizo reserves, respectively, as
of December 31, 2019.
As of December 31, 2019, Callon's estimated net proved
reserves grew 126% from prior year-end, totaling 540.0 MMboe and
included 346.4 MMBbls of oil, 757.1 Bcf of natural gas and 67.5
MMBbls of NGLs with a standardized measure of discounted future net
cash flows of $5.0 billion. Oil
constituted approximately 64% of the Company's total estimated
equivalent net proved reserves and approximately 66% of total
estimated equivalent proved developed reserves. The Company added
59.4 MMboe of new reserves in extensions and discoveries through
development efforts in each operating area, where a total of 63
gross (55.7 net) wells were drilled. The Company purchased reserves
in place of 326.8 MMboe and reduced estimated net proved
reserves through net revisions of previous estimates of 37.2
MMboe.
Callon's net revisions of previous estimates were primarily
related to technical revisions due to the observed impact of well
spacing tests on producing wells and the resulting impact on
reserve estimates as the Company advanced larger scale development
concepts across multi-zone inventory. Other impacts to
reserves included pricing effects and reclassifications of PUDs
which were mainly driven by changes in future development plans
resulting from the completion of the Carrizo acquisition which
allowed the Company to reallocate capital across the combined
companies' portfolio in an effort to increase capital efficiency
and resulting cash flow generation.
The changes in Callon's proved reserves are as follows:
|
|
Total
(MBoe)
|
Reserves at December
31, 2018
|
|
238,508
|
|
Extensions and
discoveries
|
|
59,424
|
|
Purchase of reserves
in place
|
|
326,838
|
|
Revisions to previous
estimates
|
|
(37,216)
|
|
Production
|
|
(15,086)
|
|
Sales of reserves in
place
|
|
(32,456)
|
|
Reserves at December
31, 2019
|
|
540,012
|
|
Callon replaced 212% of 2019 production as calculated by the sum
of reserve extensions and discoveries, divided by annual production
("Organic reserve replacement ratio,"(i)). The Company's
finding and development costs from extensions and discoveries
("Drill-bit F&D costs per Boe"(i)) were $15.55 per Boe calculated as accrual costs
incurred for exploration, $309.0
million, and development, $189.3
million, divided by the reserves (in barrels of oil
equivalent) added from extensions and discoveries, net of revisions
excluding reclassifications.
2019 Full Year Actuals
|
Full
Year
|
|
2019
Actual
|
Total production
(Mboe/d) (a)
|
41.3
|
% oil
|
77%
|
Income statement
expenses (per Boe)
|
|
LOE, including
workovers
|
$6.09
|
Production taxes,
including ad valorem (% unhedged revenue)
|
6%
|
Adjusted G&A:
cash component (b)
|
$2.41
|
Adjusted G&A:
non-cash component (c)
|
$0.52
|
Cash interest expense
(d)
|
$0.00
|
Effective income tax
rate
|
34.2%
|
Capital
expenditures (in millions, accrual basis)
|
|
Total operational
(e)
|
$515
|
Capitalized interest
and G&A expenses
|
$115
|
Net operated
horizontal wells placed on production
|
52
|
|
|
(a)
|
Full year 2019
production reflects the 11-day impact of Carrizo volumes included
after closing and represents Callon volumes on a 2-stream basis and
Carrizo volumes on a 3-stream basis.
|
(b)
|
Excludes the
amortization of equity-settled, share-based incentive awards,
corporate depreciation and amortization, and pending merger-related
expenses. Adjusted G&A is a non-GAAP financial measure; see the
reconciliation provided within this press release for a
reconciliation of G&A expense on a GAAP basis to Adjusted
G&A expense.
|
(c)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. Adjusted
G&A is a non-GAAP financial measure; see the reconciliation
provided within this press release for a reconciliation of G&A
expense on a GAAP basis to Adjusted G&A expense.
|
(d)
|
All cash interest
expense was capitalized.
|
(e)
|
Includes facilities,
equipment, seismic, land and other items. Excludes capitalized
expenses.
|
2020 Guidance (three-stream basis)
|
Full
Year
|
|
2020
Guidance
|
Total production
(Mboe/d) (a)
|
115.0 -
120.0
|
Oil
production
|
66%
|
NGL
production
|
17%
|
Gas
production
|
17%
|
Income statement
expenses
|
|
LOE, including
workovers (in millions)
|
$195.0 -
$235.0
|
Gathering,
processing, and transportation ($/Boe)
|
$1.55 -
$1.95
|
Production taxes,
including ad valorem (% of unhedged revenue)
|
6.5%
|
Adjusted G&A:
cash component (b) (in millions)
|
$55.0 -
$65.0
|
Adjusted G&A:
non-cash component (c) (in millions)
|
$10.0 -
$15.0
|
Cash interest
expense (in millions)
|
$55.0 -
$65.0
|
Effective income tax
rate
|
23%
|
Capital
expenditures (in millions, accrual basis)
|
|
Total operational
capital (d)
|
$975.0
|
Capitalized
interest
|
$115.0 -
$125.0
|
Capitalized
G&A
|
$45.0 -
$50.0
|
Gross operated
wells drilled / completed
|
~165 /
~160
|
|
|
(a)
|
Total Company
presented on a 3-stream basis.
|
(b)
|
Excludes the
amortization of equity-settled, share-based incentive awards and
merger-related expenses. Adjusted G&A is a non-GAAP financial
measure; see the reconciliation provided within this press release
for a reconciliation of G&A expense on a GAAP basis to Adjusted
G&A expense.
|
(c)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. Adjusted
G&A is a non-GAAP financial measure; see the reconciliation
provided within this press release for a reconciliation of G&A
expense on a GAAP basis to Adjusted G&A expense.
|
(d)
|
Includes facilities,
equipment, seismic, land and other items. Excludes capitalized
expenses.
|
Hedge Portfolio Summary
The following table summarizes our open derivative positions as
of December 31, 2019 for the periods indicated:
|
For the Full Year
of
|
|
For the Full Year
of
|
|
Oil contracts
(WTI)
|
2020
|
|
2021
|
|
Collar contracts
with short puts (three-way collars)
|
|
|
|
|
Total volume
(Bbls)
|
13,176,000
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
|
|
|
|
Ceiling (short
call)
|
$65.28
|
|
|
$—
|
|
|
Floor (long
put)
|
$55.38
|
|
|
$—
|
|
|
Floor (short
put)
|
$45.08
|
|
|
$—
|
|
|
Short call
contracts
|
|
|
|
|
Total volume
(Bbls)
|
1,674,450
|
|
(a)
|
4,825,300
|
|
(a)
|
Weighted average
price per Bbl
|
$75.98
|
|
|
$63.62
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
1,303,900
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
$55.19
|
|
|
$—
|
|
|
Swap contracts
with short puts
|
|
|
|
|
Total volume
(Bbls)
|
2,196,000
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
|
|
|
|
Swap
|
$56.06
|
|
|
$—
|
|
|
Floor (short
put)
|
$42.50
|
|
|
$—
|
|
|
|
|
|
|
|
Oil contracts
(Brent ICE)
|
|
|
|
|
Collar contracts
with short puts (three-way collars)
|
|
|
|
|
Total volume
(Bbls)
|
837,500
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
|
|
|
|
Ceiling (short
call)
|
$70.00
|
|
|
$—
|
|
|
Floor (long
put)
|
$58.24
|
|
|
$—
|
|
|
Floor (short
put)
|
$50.00
|
|
|
$—
|
|
|
|
|
|
|
|
Oil contracts
(Midland basis differential)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
8,476,700
|
|
|
4,015,100
|
|
|
Weighted average
price per Bbl
|
($1.47)
|
|
|
$0.40
|
|
|
|
|
|
|
|
Oil contracts
(Argus Houston MEH basis differential)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
1,439,205
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
$2.40
|
|
|
$—
|
|
|
|
|
|
|
|
Oil contracts
(Argus Houston MEH swaps)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(Bbls)
|
504,500
|
|
|
—
|
|
|
Weighted average
price per Bbl
|
$58.22
|
|
|
$—
|
|
|
|
|
|
|
|
Natural gas
contracts (Henry Hub)
|
|
|
|
|
Collar contracts
(three-way collars)
|
|
|
|
|
Total volume
(MMBtu)
|
3,660,000
|
|
|
—
|
|
|
Weighted average
price per MMBtu
|
|
|
|
|
Ceiling (short
call)
|
$2.75
|
|
|
$—
|
|
|
Floor (long
put)
|
$2.50
|
|
|
$—
|
|
|
Floor (short
put)
|
$2.00
|
|
|
$—
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
3,660,000
|
|
|
—
|
|
|
Weighted average
price per MMBtu
|
$2.48
|
|
|
$—
|
|
|
Short call
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
12,078,000
|
|
|
7,300,000
|
|
|
Weighted average
price per MMBtu
|
$3.50
|
|
|
$3.09
|
|
|
|
|
|
|
|
Natural gas
contracts (Waha basis differential)
|
|
|
|
|
Swap
contracts
|
|
|
|
|
Total volume
(MMBtu)
|
21,596,000
|
|
|
—
|
|
|
Weighted average
price per MMBtu
|
($1.04)
|
|
|
$—
|
|
|
|
|
(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.
|
Adjusted Income and Adjusted EBITDA. The Company
reported loss available to common stockholders of $23.5 million for the three months ended
December 31, 2019 and Adjusted Income available to common
stockholders of $56.8 million, or
$0.23 per diluted share. The
following tables reconcile the Company's income (loss) available to
common stockholders to Adjusted Income, and the Company's net
income (loss) to Adjusted EBITDA:
|
|
Three Months
Ended
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
(In thousands
except per share data)
|
Income (loss)
available to common stockholders
|
|
($23,543)
|
|
|
$47,180
|
|
|
$154,370
|
|
(Gain) loss on
derivatives contracts
|
|
30,694
|
|
|
(21,809)
|
|
|
(103,918)
|
|
Cash (paid) received
for commodity derivative settlements, net
|
|
(3,353)
|
|
|
1,011
|
|
|
(1,594)
|
|
Change in the fair
value of share-based awards
|
|
1,010
|
|
|
(925)
|
|
|
(1,053)
|
|
Merger and
integration expense
|
|
68,420
|
|
|
5,943
|
|
|
—
|
|
Other operating
expense
|
|
—
|
|
|
(175)
|
|
|
—
|
|
Loss on
extinguishment of debt
|
|
4,881
|
|
|
—
|
|
|
—
|
|
Tax effect on
adjustments above
|
|
(21,347)
|
|
|
3,351
|
|
|
22,379
|
|
Loss on redemption of
preferred stock
|
|
—
|
|
|
8,304
|
|
|
—
|
|
Change in valuation
allowance
|
|
—
|
|
|
—
|
|
|
(30,281)
|
|
Adjusted
Income
|
|
$56,762
|
|
|
$42,880
|
|
|
$39,903
|
|
Adjusted Income
per fully diluted common share
|
|
$0.23
|
|
|
$0.19
|
|
|
$0.17
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
(In
thousands)
|
Net income
(loss)
|
|
($23,543)
|
|
|
$55,834
|
|
|
$156,194
|
|
(Gain) loss on
derivatives contracts
|
|
30,694
|
|
|
(21,809)
|
|
|
(103,918)
|
|
Cash (paid) received
for commodity derivative settlements, net
|
|
(3,353)
|
|
|
1,011
|
|
|
(1,594)
|
|
Non-cash stock-based
compensation expense
|
|
3,390
|
|
|
644
|
|
|
770
|
|
Merger and
integration expense
|
|
68,420
|
|
|
5,943
|
|
|
—
|
|
Other operating
expense
|
|
145
|
|
|
(161)
|
|
|
1,333
|
|
Income tax
expense
|
|
5,857
|
|
|
17,902
|
|
|
5,647
|
|
Interest
expense
|
|
689
|
|
|
739
|
|
|
735
|
|
Depreciation,
depletion and amortization
|
|
63,198
|
|
|
57,235
|
|
|
60,549
|
|
Loss on
extinguishment of debt
|
|
4,881
|
|
|
—
|
|
|
—
|
|
Other
income
|
|
|
|
—
|
|
|
—
|
|
Adjusted
EBITDA
|
|
$150,378
|
|
|
$117,338
|
|
|
$119,716
|
|
Discretionary Cash Flow. Discretionary cash
flow(i) for the three months ended December 31,
2019 was $81.7 million and is
reconciled to net cash provided by operating activities in the
following table:
|
|
Three Months
Ended
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
(In
thousands)
|
Net income
(loss)
|
|
($23,543)
|
|
|
$55,834
|
|
|
$156,194
|
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
63,198
|
|
|
57,235
|
|
|
60,549
|
|
Amortization of
non-cash debt related items
|
|
689
|
|
|
739
|
|
|
734
|
|
Deferred income tax
expense
|
|
5,857
|
|
|
17,902
|
|
|
5,647
|
|
(Gain) loss on
derivative contracts
|
|
30,694
|
|
|
(21,809)
|
|
|
(103,918)
|
|
Cash received (paid)
for commodity derivative settlements, net
|
|
(3,353)
|
|
|
1,011
|
|
|
(1,594)
|
|
Gain on sale of other
property and equipment
|
|
(126)
|
|
|
(13)
|
|
|
(64)
|
|
Non-cash loss on
early extinguishment of debt
|
|
4,881
|
|
|
—
|
|
|
—
|
|
Non-cash expense
related to equity share-based awards
|
|
1,899
|
|
|
1,569
|
|
|
1,823
|
|
Change in the fair
value of liability share-based awards
|
|
1,518
|
|
|
(925)
|
|
|
(1,053)
|
|
Discretionary cash
flow
|
|
$81,714
|
|
|
$111,543
|
|
|
$118,318
|
|
Changes in working
capital
|
|
58,587
|
|
|
2,803
|
|
|
33,710
|
|
Payments to settle
asset retirement obligations
|
|
(2,723)
|
|
|
(654)
|
|
|
(389)
|
|
Net cash provided
by operating activities
|
|
$137,578
|
|
|
$113,692
|
|
|
$151,639
|
|
Free Cash Flow. Free cash flow(i) for the
three months ended December 31, 2019 was $9.1 million. The following table reconciles the
Company's net cash provided by operating activities to Free Cash
Flow:
|
|
Three Months
Ended
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
(In
thousands)
|
Net cash provided
by operating activities
|
|
$137,578
|
|
|
$113,692
|
|
|
$151,639
|
|
Less: Changes in
working capital
|
|
(58,587)
|
|
|
(2,803)
|
|
|
(33,710)
|
|
Plus: Payments to
settle asset retirement obligations
|
|
2,723
|
|
|
654
|
|
|
389
|
|
Plus: Merger and
integration expense
|
|
68,420
|
|
|
5,943
|
|
|
—
|
|
Plus: Other operating
expense and non-recurring items
|
|
244
|
|
|
(148)
|
|
|
1,398
|
|
Adjusted
EBITDA
|
|
$150,378
|
|
|
$117,338
|
|
|
$119,716
|
|
Less: Operational
capex (accrual)
|
|
110,021
|
|
|
116,413
|
|
|
141,177
|
|
Less: Capitalized
interest
|
|
21,781
|
|
|
18,130
|
|
|
17,500
|
|
Less: Interest
expense
|
|
689
|
|
|
739
|
|
|
735
|
|
Less: Capitalized
G&A
|
|
8,780
|
|
|
8,239
|
|
|
8,192
|
|
Free Cash
Flow
|
|
$9,107
|
|
|
($26,183)
|
|
|
($47,888)
|
|
Adjusted Total Revenue. Adjusted total
revenue(i) for the three months ended December 31,
2019 was $192.7 million and is
reconciled to total operating revenues in the following table:
|
|
Three Months
Ended
|
|
|
December 31,
2019
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
(In
thousands)
|
Operating
Revenues
|
|
|
|
|
|
|
Oil
|
|
$183,071
|
|
|
$148,210
|
|
|
$150,398
|
|
Natural
gas
|
|
10,949
|
|
|
7,168
|
|
|
11,497
|
|
Natural gas
liquids
|
|
2,075
|
|
|
—
|
|
|
—
|
|
Total operating
revenues
|
|
$196,095
|
|
|
$155,378
|
|
|
$161,895
|
|
Impact of settled
derivatives
|
|
(3,353)
|
|
|
1,011
|
|
|
(1,594)
|
|
Adjusted total
revenue
|
|
$192,742
|
|
|
$156,389
|
|
|
$160,301
|
|
PV-10. PV-10(i), as of December 31,
2019 is reconciled below to the standardized measure of discounted
future net cash flows:
|
|
As of December 31,
2019
|
|
|
(In
thousands)
|
Standardized measure
of discounted future net cash flows
|
|
$4,951,026
|
|
Add: present value of
future income taxes discounted at 10% per annum
|
|
418,555
|
|
Total Proved Reserves
- PV-10
|
|
5,369,581
|
|
Total Proved
Developed Reserves - PV-10
|
|
3,246,802
|
|
Total Proved
Undeveloped Reserves - PV-10
|
|
$2,122,779
|
|
Callon Petroleum
Company
Consolidated
Balance Sheets
(in thousands,
except par values and share data)
|
|
|
December
31,
|
|
2019
|
|
2018
|
ASSETS
|
|
|
|
Current
assets:
|
|
|
|
Cash and
cash equivalents
|
$
|
13,341
|
|
|
$
|
16,051
|
|
Accounts
receivable, net
|
209,463
|
|
|
131,720
|
|
Fair
value of derivatives
|
26,056
|
|
|
65,114
|
|
Other
current assets
|
19,814
|
|
|
9,740
|
|
Total current
assets
|
268,674
|
|
|
222,625
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
Evaluated properties,
net
|
4,682,994
|
|
|
2,314,345
|
|
Unevaluated
properties
|
1,986,124
|
|
|
1,404,513
|
|
Total oil and natural
gas properties, net
|
6,669,118
|
|
|
3,718,858
|
|
Operating lease
right-of-use assets
|
63,908
|
|
|
—
|
|
Other property and
equipment, net
|
35,253
|
|
|
21,901
|
|
Deferred tax
asset
|
115,720
|
|
|
—
|
|
Deferred financing
costs
|
22,233
|
|
|
6,087
|
|
Fair value of
derivatives
|
9,216
|
|
|
—
|
|
Other assets,
net
|
10,716
|
|
|
9,702
|
|
Total
assets
|
$
|
7,194,838
|
|
|
$
|
3,979,173
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts
payable and accrued liabilities
|
$
|
511,622
|
|
|
$
|
285,849
|
|
Operating lease liabilities
|
42,858
|
|
|
—
|
|
Fair
value of derivatives
|
71,197
|
|
|
10,480
|
|
Other
current liabilities
|
26,570
|
|
|
18,587
|
|
Total current
liabilities
|
652,247
|
|
|
314,916
|
|
Long-term
debt
|
3,186,109
|
|
|
1,189,473
|
|
Operating lease
liabilities
|
37,088
|
|
|
—
|
|
Asset retirement
obligations
|
48,860
|
|
|
10,405
|
|
Deferred tax
liability
|
—
|
|
|
9,564
|
|
Fair value of
derivatives
|
32,695
|
|
|
7,440
|
|
Other long-term
liabilities
|
14,531
|
|
|
2,167
|
|
Total
liabilities
|
3,971,530
|
|
|
1,533,965
|
|
Commitments and
contingencies
|
|
|
|
Stockholders'
equity:
|
|
|
|
Preferred stock, series A cumulative, $0.01 par value and $50.00
liquidation preference, 2,500,000 shares authorized: 0 and
1,458,948 shares outstanding, respectively
|
—
|
|
|
15
|
|
Common
stock, $0.01 par value, 525,000,000 and 300,000,000 shares
authorized, respective; 396,600,022 and 227,582,575 shares
outstanding, respectively
|
3,966
|
|
|
2,276
|
|
Capital
in excess of par
|
3,198,076
|
|
|
2,477,278
|
|
Retained
earnings (Accumulated deficit)
|
21,266
|
|
|
(34,361)
|
|
Total stockholders'
equity
|
3,223,308
|
|
|
2,445,208
|
|
Total liabilities and
stockholders' equity
|
$
|
7,194,838
|
|
|
$
|
3,979,173
|
|
Callon Petroleum
Company
Consolidated
Statements of Operations
(in thousands,
except per share data)
|
|
|
Three Months
Ended
December 31,
|
|
For the Year
Ended
December 31,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Operating
Revenues:
|
|
|
|
|
|
|
|
Oil
|
$
|
183,071
|
|
|
$
|
150,398
|
|
|
$
|
633,107
|
|
|
$
|
530,898
|
|
Natural
gas
|
10,949
|
|
|
11,497
|
|
|
36,390
|
|
|
56,726
|
|
Natural gas
liquids
|
2,075
|
|
|
—
|
|
|
2,075
|
|
|
—
|
|
Total operating
revenues
|
196,095
|
|
|
161,895
|
|
|
671,572
|
|
|
587,624
|
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
Lease
operating
|
25,316
|
|
|
24,475
|
|
|
91,827
|
|
|
69,180
|
|
Production
taxes
|
8,841
|
|
|
9,490
|
|
|
42,651
|
|
|
35,755
|
|
Depreciation,
depletion and amortization
|
61,367
|
|
|
59,750
|
|
|
240,642
|
|
|
182,783
|
|
General and
administrative
|
13,626
|
|
|
8,514
|
|
|
45,331
|
|
|
35,293
|
|
Merger and
integration expenses
|
68,420
|
|
|
—
|
|
|
74,363
|
|
|
—
|
|
Settled share-based
awards
|
—
|
|
|
—
|
|
|
3,024
|
|
|
—
|
|
Other operating
expense
|
145
|
|
|
1,333
|
|
|
1,076
|
|
|
5,083
|
|
Total operating
expenses
|
177,715
|
|
|
103,562
|
|
|
498,914
|
|
|
328,094
|
|
Income From
Operations
|
18,380
|
|
|
58,333
|
|
|
172,658
|
|
|
259,530
|
|
|
|
|
|
|
|
|
|
Other (Income)
Expenses:
|
|
|
|
|
|
|
|
Interest expense, net
of capitalized amounts
|
689
|
|
|
735
|
|
|
2,907
|
|
|
2,500
|
|
(Gain) loss on
derivative contracts
|
30,694
|
|
|
(103,918)
|
|
|
62,109
|
|
|
(48,544)
|
|
Loss on
extinguishment of debt
|
4,881
|
|
|
—
|
|
|
4,881
|
|
|
—
|
|
Other
income
|
(198)
|
|
|
(325)
|
|
|
(468)
|
|
|
(2,896)
|
|
Total other (income)
expense
|
36,066
|
|
|
(103,508)
|
|
|
69,429
|
|
|
(48,940)
|
|
|
|
|
|
|
|
|
|
Income (Loss)
Before Income Taxes
|
(17,686)
|
|
|
161,841
|
|
|
103,229
|
|
|
308,470
|
|
Income tax
expense
|
5,857
|
|
|
5,647
|
|
|
35,301
|
|
|
8,110
|
|
Net Income
(Loss)
|
(23,543)
|
|
|
156,194
|
|
|
67,928
|
|
|
300,360
|
|
Preferred stock
dividends
|
—
|
|
|
(1,824)
|
|
|
(3,997)
|
|
|
(7,295)
|
|
Loss on redemption of
preferred stock
|
—
|
|
|
—
|
|
|
(8,304)
|
|
|
—
|
|
Income (Loss)
Available to Common Stockholders
|
$
|
(23,543)
|
|
|
$
|
154,370
|
|
|
$
|
55,627
|
|
|
$
|
293,065
|
|
|
|
|
|
|
|
|
|
Income (Loss)
Available to Common Stockholders Per Common Share:
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.09)
|
|
|
$
|
0.68
|
|
|
$
|
0.24
|
|
|
$
|
1.35
|
|
Diluted
|
$
|
(0.09)
|
|
|
$
|
0.68
|
|
|
$
|
0.24
|
|
|
$
|
1.35
|
|
|
|
|
|
|
|
|
|
Weighted Average
Common Shares Outstanding:
|
|
|
|
|
|
|
|
Basic
|
248,232
|
|
|
227,580
|
|
|
233,140
|
|
|
216,941
|
|
Diluted
|
248,359
|
|
|
228,191
|
|
|
233,550
|
|
|
217,596
|
|
Callon Petroleum
Company
Consolidated
Statements of Cash Flows
(in
thousands)
|
|
|
Three Months
Ended
December 31,
|
|
For the Year
Ended
December 31,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
($23,543)
|
|
|
$156,194
|
|
|
$67,928
|
|
|
$300,360
|
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
63,198
|
|
|
60,549
|
|
|
245,936
|
|
|
185,605
|
|
Amortization
of non-cash debt related items
|
689
|
|
|
734
|
|
|
2,907
|
|
|
2,483
|
|
Deferred
income tax (benefit) expense
|
5,857
|
|
|
5,647
|
|
|
35,301
|
|
|
8,110
|
|
(Gain) loss on
derivative contracts
|
30,694
|
|
|
(103,918)
|
|
|
62,109
|
|
|
(48,544)
|
|
Cash paid for
commodity derivative settlements, net
|
(3,353)
|
|
|
(1,594)
|
|
|
(3,789)
|
|
|
(27,272)
|
|
Gain on sale
of other property and equipment
|
(126)
|
|
|
(64)
|
|
|
(90)
|
|
|
(144)
|
|
Non-cash loss
on early extinguishment of debt
|
4,881
|
|
|
—
|
|
|
4,881
|
|
|
—
|
|
Non-cash
expense related to equity share-based awards
|
1,899
|
|
|
1,823
|
|
|
9,767
|
|
|
6,289
|
|
Change in the
fair value of liability share-based awards
|
1,518
|
|
|
(1,053)
|
|
|
1,624
|
|
|
375
|
|
Payments to
settle asset retirement obligations
|
(2,723)
|
|
|
(389)
|
|
|
(4,148)
|
|
|
(1,469)
|
|
Payments for
cash-settled restricted stock unit awards
|
—
|
|
|
—
|
|
|
(1,425)
|
|
|
(4,990)
|
|
Changes in
current assets and liabilities:
|
|
|
|
|
|
|
|
Accounts receivable
|
(52,671)
|
|
|
37,033
|
|
|
(35,071)
|
|
|
(17,351)
|
|
Other current assets
|
1,006
|
|
|
(5,936)
|
|
|
(4,166)
|
|
|
(7,601)
|
|
Current liabilities
|
99,476
|
|
|
9,510
|
|
|
86,438
|
|
|
74,311
|
|
Other long-term liabilities
|
—
|
|
|
(6,065)
|
|
|
—
|
|
|
—
|
|
Other
|
10,776
|
|
|
(832)
|
|
|
8,114
|
|
|
(2,508)
|
|
Net cash provided by operating activities
|
137,578
|
|
|
151,639
|
|
|
476,316
|
|
|
467,654
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
(137,115)
|
|
|
(155,821)
|
|
|
(640,540)
|
|
|
(611,173)
|
|
Acquisitions
|
(1,478)
|
|
|
(122,809)
|
|
|
(42,266)
|
|
|
(718,793)
|
|
Additions to other
assets
|
—
|
|
|
(3,100)
|
|
|
—
|
|
|
(3,100)
|
|
Proceeds from sales
of assets
|
14,465
|
|
|
683
|
|
|
294,417
|
|
|
9,009
|
|
Net cash used in investing activities
|
(124,128)
|
|
|
(281,047)
|
|
|
(388,389)
|
|
|
(1,324,057)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
1,874,900
|
|
|
230,000
|
|
|
2,455,900
|
|
|
500,000
|
|
Payments on senior
secured revolving credit facility
|
(314,500)
|
|
|
(95,000)
|
|
|
(895,500)
|
|
|
(325,000)
|
|
Repayment of 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 6.375%
senior unsecured notes due 2026
|
—
|
|
|
—
|
|
|
—
|
|
|
400,000
|
|
Issuance of common
stock
|
—
|
|
|
(376)
|
|
|
—
|
|
|
287,988
|
|
Payment of preferred
stock dividends
|
—
|
|
|
(1,824)
|
|
|
(3,997)
|
|
|
(7,295)
|
|
Payment of deferred
financing costs
|
(22,449)
|
|
|
530
|
|
|
(22,480)
|
|
|
(9,430)
|
|
Tax withholdings
related to restricted stock units
|
(21)
|
|
|
—
|
|
|
(2,195)
|
|
|
(1,804)
|
|
Redemption of
preferred stock
|
—
|
|
|
—
|
|
|
(73,017)
|
|
|
—
|
|
Net cash provided by (used in) financing activities
|
(11,418)
|
|
|
133,330
|
|
|
(90,637)
|
|
|
844,459
|
|
Net change in cash
and cash equivalents
|
2,032
|
|
|
3,922
|
|
|
(2,710)
|
|
|
(11,944)
|
|
Balance,
beginning of period
|
11,309
|
|
|
12,129
|
|
|
16,051
|
|
|
27,995
|
|
Balance, end
of period
|
$13,341
|
|
|
$16,051
|
|
|
$13,341
|
|
|
$16,051
|
|
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as
"Drill-bit F&D costs per Boe," "PD F&D costs per Boe,"
"Operating margin per Boe," "free cash flow," "Organic reserve
replacement ratio," "PV-10," "Discretionary Cash Flow," "Adjusted
G&A," "Adjusted Income," "Adjusted EBITDA" and "Adjusted Total
Revenue." 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.
- Callon believes that the non-GAAP measure of discretionary 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. Discretionary cash flow is defined by Callon as net cash
provided by operating activities before changes in working capital
and payments to settle asset retirement obligations and vested
liability share-based awards. 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 in the
period in which the operating activities occurred. 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 (as defined under GAAP), or
as a measure of liquidity, or as an alternative to net income.
- Callon believes that the non-GAAP measure of 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 after internally funding their
capital development program and servicing their existing debt. Free
cash flow is defined by Callon as Adjusted EBITDA (as defined
below) less accrual-based capital expenditures and interest
expense. 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 (as
defined under GAAP), or as a measure of liquidity, or as an
alternative to net income.
- 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, as well as
non-cash corporate depreciation and amortization expense. 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. The table contained within this release details
all adjustments to G&A on a GAAP basis to arrive at Adjusted
G&A.
- Callon believes that the non-GAAP measure of Adjusted Income
available to common shareholders ("Adjusted Income") and Adjusted
Income per fully diluted common share are useful to investors
because they provide a meaningful measure of our profitability that
does not take into account certain items whose timing or amount
cannot be reasonably determined. These measures exclude the net of
tax effects of certain non-recurring items and non-cash valuation
adjustments, which are detailed in the reconciliation
provided.
- Callon calculates adjusted earnings before interest, income
taxes, depreciation, depletion and amortization ("Adjusted EBITDA")
as net income (loss) before interest expense, income taxes,
depreciation, depletion and amortization, asset retirement
obligation accretion expense, (gains) losses on derivative
instruments excluding net settled derivative instruments,
impairment of oil and natural gas properties, non-cash equity based
compensation, 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 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.
- We believe Drill-Bit F&D costs per Boe and Organic reserve
replacement ratio are non-GAAP metrics commonly used by companies
in our industry, as well as analysts and investors, to measure and
evaluate the cost of replenishing annual production and adding
proved reserves. The Company's definitions of Drill-Bit F&D
costs per Boe and Organic reserve replacement ratio may differ
significantly from definitions used by other companies to compute
similar measures and as a result may not be comparable to similar
measures provided by other companies. Consequently, we provided the
detail of our calculation within the included tables.
- 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 ("Standardized Measure"). Pre-tax PV-10 is calculated
using the Standardized Measure before deducting future income
taxes, discounted at 10 percent. The 12-month average benchmark
pricing used to estimate proved reserves in accordance with the
definitions and regulations of the SEC and pre-tax PV-10 value for
crude oil and natural gas was $55.69
per Bbl of WTI crude oil and $2.58
per MMBtu of natural gas at Henry Hub before differential
adjustments. After differential adjustments, the Company's SEC
pricing realizations for year-end 2019 were $53.90 per Bbl of oil and $1.55 per Mcf of natural gas.
Earnings Call Information
The Company will host a conference call on Thursday, February 27, 2020, to discuss fourth
quarter 2019 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Thursday, February
27, 2020, 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.
|
Alternatively, you may join by telephone using the following
numbers:
Domestic:
|
1-888-317-6003
|
Canada:
|
1-866-284-3684
|
International:
|
1-412-317-6061
|
Access
code:
|
8524953
|
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 drilling
activity and associated production and cash flow expectations; the
Company's 2020 production guidance and capital expenditure
forecast; 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; 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; the ultimate timing, outcome and results of integrating
the operations of Carrizo and Callon; the effects of the business
combination of Carrizo and Callon, including the Company's future
financial condition, results of operations, strategy and plans; the
ability of the combined company to realize anticipated synergies
and other benefits in the timeframe expected or at all; 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
(i)
|
Non-GAAP measure. See
"Non-GAAP Financial Measures and Reconciliations" included within
this release for related disclosures and calculations
|
View original
content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-fourth-quarter-and-full-year-2019-results-and-provides-integrated-2020-plan-301012123.html
SOURCE Callon Petroleum Company