Callon Petroleum Company Announces Fourth Quarter and Full Year 2019 Results and Provides Integrated 2020 Plan
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 For the Full Year
of 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 For the Year Ended
December 31, 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 For the Year Ended
December 31, 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
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SOURCE Callon Petroleum Company
