NATCHEZ, Miss., Nov. 6,
2017 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE)
("Callon" or the "Company") today reported results of operations
for the three months ended September 30, 2017.
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.
Financial and operational highlights for the third quarter of
2017, and other recent data points include:
- Increased production by 36% year-over-year, with an increased
percentage of oil volumes
- Reduced lease operating expense by 9% on a sequential basis to
$5.08 per BOE, contributing to a
total reduction of 23% since the first quarter of 2017
- Generated a third quarter operating margin of $32.58 per BOE
- First operated Delaware Basin
Lower Wolfcamp A well had a 24 hour peak flowing rate of 238 BOE/d
per 1,000' (82% oil)
- Successful return to Ranger drilling program with two Lower
Wolfcamp B wells outperforming previous type curves
Joe Gatto, Chief Executive
Officer and President commented, "This quarter's results speak to
our team's commitment to generating strong returns by focusing on
driving down costs while extracting the best well results possible
from our premier asset base. Consistent improvement in our already
strong cash margins, despite production deferrals during the
quarter, is evidence that we are taking the correct steps to create
shareholder value. Our goal is to manage growth as a function of
creating returns on our capital investment. We have been consistent
in our focus on these priorities and will continue to be into
2018." He continued, "Callon's well results were strong across all
four of our operations areas during the third quarter, including
our first operated well in the Delaware Basin. Early well results in the
fourth quarter have been equally strong and we are excited about
our prospects for 2018."
Operations Update
At September 30, 2017, we had 218 gross (161.2 net)
horizontal wells producing from seven established flow units in the
Permian Basin. Net daily production for the three months ended
September 30, 2017 grew approximately 36% to 22.5 thousand
barrels of oil equivalent per day (approximately 77% oil) as
compared to the same period of 2016.
For the three months ended September 30, 2017, we operated
four horizontal drilling rigs, drilling 13 gross (10.3 net)
horizontal wells in the Spur, WildHorse, Ranger and Monarch areas.
We placed a combined 11 gross (10.1 net) horizontal wells on
production in the quarter in these areas.
In the Delaware Basin, we
drilled and completed our first operated Lower Wolfcamp A well, the
Sleeping Indian A1 #1LA well. The well is currently
outperforming the 7,500 foot type curve, with an oil cut of
approximately 82%. We recently completed our second operated well,
the Saratoga A1 #7LA and have
placed the well on flowback. We expect to commence multi-well pad
development prior to the end of this year with co-development of
the Upper and Lower Wolfcamp A.
In the Midland Basin, we were active across all three focus
areas: WildHorse, Ranger and Monarch. In Howard County at our
WildHorse area, we placed multiple Wolfcamp A wells on production
during the second half of the quarter. The wells are cleaning up
and have shown similar productivity to our previous wells in the
area on an early time basis. Our plans are to continue program
development of multiple zones across our footprint and we also
expect to test tighter Wolfcamp A spacing, at 10 wells per section,
in 2018.
In Reagan County at our Ranger area, our first operated Lower
Wolfcamp B wells since 2015 are outperforming the type curve by
more than 20%. During the quarter, we drilled our first Wolfcamp C
well in this area, which is scheduled for completion during the
fourth quarter along with two additional Lower Wolfcamp B wells. We
currently do not account for any Wolfcamp C locations in our
delineated inventory.
At our Monarch area in Midland County, we drilled a three-well
pad consisting of our longest wells to date at an average of over
21,000 feet true measured depth. The completed lateral length for
these wells averaged approximately 10,600 feet and the wells are
entering their fourth week of flowback.
Infrastructure investment continued to be a key focus in the
third quarter. We realized an impressive reduction in lease
operating expenses this quarter, and we expect this infrastructure
investment to continue to improve operating margins as well as
position Callon as an environmentally-responsible operator for the
long term. We continued to invest in saltwater disposal wells in
the Midland Basin and Delaware
Basin, resulting in increased disposal capacity and reduced
disposal costs. In addition, we have begun utilizing recycled
water volumes in the Midland Basin and are currently preparing
infrastructure at our Spur asset to implement water recycling for
our planned two rig program in 2018. Importantly, after developing
a substantial base of Callon-owned infrastructure, we are now
positioned to selectively monetize portions of our asset base while
ensuring reliable operations. As an initial step in this
initiative, we expect to complete at least $20 million of such transactions in the fourth
quarter, with other identified transactions expected to close by
the end of the first quarter of 2018.
Capital
Expenditures
|
|
For the three months
ended September 30, 2017, we incurred $112.7 million in cash
operational capital expenditures (excluding other
items) compared to $64.0 million in the second quarter of
2017. Total capital expenditures, inclusive of capitalized
expenses, are detailed below on an accrual and cash basis (in
thousands):
|
|
|
|
Three Months Ended
September 30, 2017
|
|
|
Operational
|
|
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
|
Capital
|
|
Other
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
Cash basis
(b)
|
|
$
|
112,667
|
|
|
$
|
3,767
|
|
|
$
|
479
|
|
|
$
|
4,215
|
|
|
$
|
121,128
|
|
Timing adjustments
(c)
|
|
711
|
|
|
—
|
|
|
9,119
|
|
|
—
|
|
|
9,830
|
|
Non-cash
items
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,133
|
|
|
1,133
|
|
Accrual
(GAAP) basis
|
|
$
|
113,378
|
|
|
$
|
3,767
|
|
|
$
|
9,598
|
|
|
$
|
5,348
|
|
|
$
|
132,091
|
|
|
|
(a)
|
Includes seismic,
land and other items.
|
(b)
|
Cash basis is a
non-GAAP measure that we believe helps users of the financial
information reconcile amounts to the cash flow statement and to
account for timing related operational changes such as our
development pace and rig count.
|
(c)
|
Includes timing
adjustments related to cash disbursements in the current period for
capital expenditures incurred in the prior period.
|
Operating and
Financial Results
|
|
The following table
presents summary information for the periods indicated:
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2017
|
|
June 30,
2017
|
|
September 30,
2016
|
Net
production:
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
1,591
|
|
|
1,596
|
|
|
1,153
|
|
Natural gas
(MMcf)
|
|
2,900
|
|
|
2,550
|
|
|
2,244
|
|
Total production
(MBOE)
|
|
2,074
|
|
|
2,021
|
|
|
1,527
|
|
Average daily
production (BOE/d)
|
|
22,543
|
|
|
22,209
|
|
|
16,598
|
|
% oil
(BOE basis)
|
|
77
|
%
|
|
79
|
%
|
|
76
|
%
|
Oil
and natural gas revenues (in thousands):
|
|
|
|
|
|
|
Oil
revenue
|
|
$
|
73,349
|
|
|
$
|
72,885
|
|
|
$
|
49,095
|
|
Natural
gas revenue
|
|
11,265
|
|
|
9,398
|
|
|
6,832
|
|
Total
revenue
|
|
84,614
|
|
|
82,283
|
|
|
55,927
|
|
Impact
of cash-settled derivatives
|
|
(1,214)
|
|
|
(267)
|
|
|
4,091
|
|
Adjusted Total Revenue
(i)
|
|
$
|
83,400
|
|
|
$
|
82,016
|
|
|
$
|
60,018
|
|
Average realized
sales price:
|
|
|
|
|
|
|
Oil
(Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
46.10
|
|
|
$
|
45.67
|
|
|
$
|
42.58
|
|
Oil
(Bbl) (including impact of cash settled derivatives)
|
|
45.24
|
|
|
45.47
|
|
|
46.27
|
|
Natural
gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
3.88
|
|
|
$
|
3.69
|
|
|
$
|
3.04
|
|
Natural
gas (Mcf) (including impact of cash settled derivatives)
|
|
3.94
|
|
|
3.70
|
|
|
2.97
|
|
Total
(BOE) (excluding impact of cash settled derivatives)
|
|
$
|
40.80
|
|
|
$
|
40.71
|
|
|
$
|
36.63
|
|
Total
(BOE) (including impact of cash settled derivatives)
|
|
40.21
|
|
|
40.58
|
|
|
39.30
|
|
Additional per BOE
data:
|
|
|
|
|
|
|
Sales
price (excluding impact of cash settled derivatives)
|
|
$
|
40.80
|
|
|
$
|
40.71
|
|
|
$
|
36.63
|
|
Lease operating
expense (excluding gathering and treating
|
|
|
|
|
|
|
expense)
|
|
5.08
|
|
|
5.56
|
|
|
6.16
|
|
Gathering and treating
expense
|
|
0.52
|
|
|
0.45
|
|
|
0.36
|
|
Production
taxes
|
|
2.62
|
|
|
2.38
|
|
|
2.28
|
|
Operating margin
|
|
$
|
32.58
|
|
|
$
|
32.32
|
|
|
$
|
27.83
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
$
|
13.75
|
|
|
$
|
12.97
|
|
|
$
|
11.33
|
|
Adjusted
G&A (a)
|
|
|
|
|
|
|
Cash component
(b)
|
|
$
|
2.50
|
|
|
$
|
2.67
|
|
|
$
|
2.38
|
|
Non-cash
component
|
|
0.65
|
|
|
0.53
|
|
|
0.58
|
|
|
|
(a)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. See the
reconciliation provided within this press release for a
reconciliation of G&A expense on a GAAP basis to Adjusted
G&A expense.
|
(b)
|
Excludes the
amortization of equity-settled share-based incentive awards and
corporate depreciation and amortization.
|
Total Revenue. For the quarter ended
September 30, 2017, Callon reported total revenue of
$84.6 million and total revenue
including cash-settled derivatives ("Adjusted Total Revenue," a
non-GAAP financial measure(i)) of $83.4 million, including the impact of a
$1.2 million loss from the settlement
of derivative contracts. The table above reconciles Adjusted Total
Revenue to the related GAAP measure of the Company's revenue.
Average daily production for the quarter was 22.5 MBOE/d compared
to average daily production of 22.2 MBOE/d in the second quarter of
2017. Average realized prices, including and excluding the effects
of hedging, are detailed below.
Hedging impacts. For the quarter ended September 30,
2017, Callon recognized the following hedging-related items (in
thousands, except per unit data):
|
In
Thousands
|
|
Per
Unit
|
Oil
derivatives
|
|
|
|
Net loss on
settlements
|
$
|
(1,373)
|
|
|
$
|
(0.86)
|
|
Net loss on fair
value adjustments
|
(12,811)
|
|
|
|
Total
loss on oil derivatives
|
$
|
(14,184)
|
|
|
|
Natural gas
derivatives
|
|
|
|
Net gain on
settlements
|
$
|
159
|
|
|
$
|
0.06
|
|
Net loss on fair
value adjustments
|
(137)
|
|
|
|
Total
gain on natural gas derivatives
|
$
|
22
|
|
|
|
Total oil &
natural gas derivatives
|
|
|
|
Net loss on
settlements
|
$
|
(1,214)
|
|
|
$
|
(0.59)
|
|
Net loss on fair
value adjustments
|
(12,948)
|
|
|
|
Total
loss on total oil & natural gas derivatives
|
$
|
(14,162)
|
|
|
|
Lease Operating Expenses, including workover and gathering
expense ("LOE"). LOE per BOE for the three months ended
September 30, 2017 was $5.60 per
BOE, compared to LOE of $6.01 per BOE
in the second quarter of 2017. The decrease in this metric resulted
primarily from a decrease in the number of workovers period over
period.
Production Taxes, including ad valorem taxes. Production
taxes were $2.62 per BOE for the
three months ended September 30, 2017, representing
approximately 6.4% of total revenue before the impact of derivative
settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
September 30, 2017 was $13.75
per BOE compared to $12.97 per BOE in
the second quarter of 2017. The increase on a per unit basis was
primarily attributable to greater increases in our depreciable
asset base and assumed future development costs related to
undeveloped proved reserves as compared to the estimated total
proved reserve base.
General and Administrative ("G&A"). G&A,
excluding certain non-cash incentive share-based compensation
valuation adjustments, ("Adjusted G&A", a non-GAAP
measure(i)) was $6.5
million, or $3.15 per BOE, for
the three months ended September 30, 2017 compared to
$6.5 million, or $3.20 per BOE, for the second quarter of 2017.
The cash component of Adjusted G&A was $5.2 million, or $2.50 per BOE, for the three months ended
September 30, 2017 compared to $5.4
million, or $2.67 per BOE, for
the second quarter of 2017.
For the three months ended September 30, 2017, 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
September 30, 2017
|
Total G&A
expense
|
$
|
7,259
|
|
Less:
Change in the fair value of liability share-based awards
(non-cash)
|
(731)
|
|
Adjusted G&A –
total
|
6,528
|
|
Less:
Restricted stock share-based compensation (non-cash)
|
(1,198)
|
|
Less:
Corporate depreciation & amortization (non-cash)
|
(146)
|
|
Adjusted G&A –
cash component
|
$
|
5,184
|
|
Income tax expense. Callon typically provides for income
taxes at a statutory rate of 35% adjusted for permanent
differences expected to be realized, which primarily relate to
non-deductible executive compensation expenses and state income
taxes. We recorded an income tax expense of $0.2 million for the three months ended
September 30, 2017 which relates to deferred State of Texas gross margin tax. At
September 30, 2017 we had a valuation allowance of
$109.8 million. Adjusted Income per
fully diluted common share, a non-GAAP financial
measure(i), adjusts our income (loss) available to
common stockholders to reflect our theoretical tax provision of
$6.1 million (or $0.03 per diluted share) for the quarter as if
the valuation allowance did not exist.
2017 Guidance
Update
|
|
|
|
Fourth
Quarter
|
|
|
2017
Guidance
|
Total production
(BOE/d)
|
|
24,000 -
25,500
|
% oil
|
|
77 %
|
Income Statement
Expenses (per BOE)
|
|
|
LOE, including
workovers
|
|
$5.75 -
$6.25
|
Gathering and
treating
|
|
$0.55 -
$0.65
|
Production taxes,
including ad valorem (% unhedged revenue)
|
|
7%
|
Adjusted
G&A: cash component (a)
|
|
$2.25 -
$2.50
|
Adjusted
G&A: non-cash component (b)
|
|
$0.55 -
$0.65
|
Interest
expense (c)
|
|
$0.00
|
Effective income tax
rate
|
|
0%
|
Capital
expenditures ($MM, accrual basis)
|
|
|
Total Operational
(net of monetizations) (d)
|
|
$108 - $112 ($88 -
$92)
|
Capitalized expenses
(cash component)
|
|
$13 - $17
|
Net operated
horizontal well completions
|
|
|
Midland
Basin
|
|
~12
|
Delaware
Basin
|
|
~1
|
|
|
(a)
|
Excludes stock-based
compensation and corporate depreciation and amortization. See the
Non-GAAP related disclosures referenced in the footnote (b)
below.
|
(b)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. The
reconciliation above provides a reconciliation of third quarter
2017 G&A expense on a GAAP basis to Adjusted G&A expense, a
non-GAAP measure. The Company is unable to present a quantitative
reconciliation of this forward-looking non-GAAP financial measure
without unreasonable effort because of the number of estimated
variables that could affect the final value. Accordingly, investors
are cautioned not to place undue reliance on this
information.
|
(c)
|
All interest expense
anticipated to be capitalized.
|
(d)
|
Includes seismic,
land and other items. Excludes capitalized expenses.
|
Hedge Portfolio
Summary
|
|
The following tables
summarize our open derivative positions for the periods
indicated:
|
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Oil contracts
(WTI)
|
2017
|
|
2018
|
Swap contracts
combined with short puts (enhanced swaps)
|
|
|
|
Total volume
(MBbls)
|
184
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Swap
|
$
|
44.50
|
|
|
$
|
—
|
|
Short put
option
|
$
|
30.00
|
|
|
$
|
—
|
|
Swap
contracts
|
|
|
|
Total volume
(MBbls)
|
184
|
|
|
1,825
|
|
Weighted average
price per Bbl
|
$
|
45.74
|
|
|
$
|
51.42
|
|
Deferred premium
put spread option
|
|
|
|
Total volume
(MBbls)
|
253
|
|
|
—
|
|
Premium per
Bbl
|
$
|
2.45
|
|
|
$
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Long put
option
|
$
|
50.00
|
|
|
$
|
—
|
|
Short put
option
|
$
|
40.00
|
|
|
$
|
—
|
|
Collar contracts
(two-way collars)
|
|
|
|
Total volume
(MBbls)
|
340
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Ceiling (short
call)
|
$
|
58.19
|
|
|
$
|
—
|
|
Floor (long
put)
|
$
|
47.50
|
|
|
$
|
—
|
|
Call option
contracts
|
|
|
|
Total volume
(MBbls)
|
169
|
|
|
—
|
|
Premium per
Bbl
|
$
|
1.82
|
|
|
$
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Short call strike price
(a)
|
$
|
50.00
|
|
|
$
|
—
|
|
Long call strike price
(a)
|
$
|
50.00
|
|
|
$
|
—
|
|
Collar contracts
combined with short puts (three-way collars)
|
|
|
|
Total volume
(MBbls)
|
—
|
|
|
3,468
|
|
Weighted average
price per Bbl
|
|
|
|
Ceiling (short
call option)
|
$
|
—
|
|
|
$
|
60.86
|
|
Floor (long
put option)
|
$
|
—
|
|
|
$
|
48.95
|
|
Short put
option
|
$
|
—
|
|
|
$
|
39.21
|
|
|
|
(a)
|
Offsetting
contracts.
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Oil contracts
(Midland basis differential)
|
2017
|
|
2018
|
Swap
contracts
|
|
|
|
Volume
(MBbls)
|
552
|
|
|
5,109
|
|
Weighted average
price per Bbl
|
$
|
(0.52)
|
|
|
$
|
(0.90)
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Natural gas
contracts (Henry Hub)
|
2017
|
|
2018
|
Collar contracts
combined with short puts (three-way collars)
|
|
|
|
Total volume
(BBtu)
|
368
|
|
|
—
|
|
Weighted average
price per MMBtu
|
|
|
|
Ceiling (short
call option)
|
$
|
3.71
|
|
|
$
|
—
|
|
Floor (long
put option)
|
$
|
3.00
|
|
|
$
|
—
|
|
Short put
option
|
$
|
2.50
|
|
|
$
|
—
|
|
Collar contracts
(two-way collars)
|
|
|
|
Total volume
(BBtu)
|
856
|
|
|
720
|
|
Weighted average
price per MMBtu
|
|
|
|
Ceiling (short
call option)
|
$
|
3.77
|
|
|
$
|
3.84
|
|
Floor (long
put option)
|
$
|
3.23
|
|
|
$
|
3.40
|
|
Swap
contracts
|
|
|
|
Total volume
(BBtu)
|
124
|
|
|
—
|
|
Weighted average
price per MMBtu
|
$
|
3.39
|
|
|
$
|
—
|
|
Income (Loss) Available to Common Shareholders. The
Company reported net income available to common shareholders of
$15.3 million for the three months
ended September 30, 2017 and Adjusted Income available to
common shareholders of $18.1 million,
or $0.09 per diluted share. Adjusted
Income per fully diluted common share, a non-GAAP financial
measure(i), adjusts our income (loss) available to
common stockholders to reflect our theoretical tax provision for
the quarter as if the valuation allowance did not exist. The
following tables reconcile to the related GAAP measure the
Company's income (loss) available to common stockholders to
Adjusted Income and the Company's net income (loss) to Adjusted
EBITDA (in thousands):
|
Three Months
Ended
|
|
September 30,
2017
|
|
June 30,
2017
|
|
September 30,
2016
|
Income available to
common stockholders
|
$
|
15,257
|
|
|
$
|
31,566
|
|
|
$
|
19,315
|
|
Change
in valuation allowance
|
(6,064)
|
|
|
(11,194)
|
|
|
(7,907)
|
|
Net
(gain) loss on derivatives, net of settlements
|
8,416
|
|
|
(6,995)
|
|
|
(679)
|
|
Change
in the fair value of share-based awards
|
475
|
|
|
(315)
|
|
|
2,192
|
|
Settled
share-based awards
|
—
|
|
|
4,128
|
|
|
—
|
|
Adjusted
Income
|
$
|
18,084
|
|
|
$
|
17,190
|
|
|
$
|
12,921
|
|
Adjusted Income per
fully diluted common share
|
$
|
0.09
|
|
|
$
|
0.09
|
|
|
$
|
0.09
|
|
|
|
|
Three Months
Ended
|
|
September 30,
2017
|
|
June 30,
2017
|
|
September 30,
2016
|
Net income
|
$
|
17,081
|
|
|
$
|
33,390
|
|
|
$
|
21,139
|
|
Net
(gain) loss on derivatives, net of settlements
|
12,947
|
|
|
(10,761)
|
|
|
(1,044)
|
|
Non-cash
stock-based compensation expense
|
1,952
|
|
|
499
|
|
|
4,150
|
|
Settled
share-based awards
|
—
|
|
|
6,351
|
|
|
—
|
|
Acquisition expense
|
205
|
|
|
2,373
|
|
|
456
|
|
Income
tax (benefit) expense
|
237
|
|
|
322
|
|
|
(62)
|
|
Interest
expense
|
444
|
|
|
589
|
|
|
831
|
|
Depreciation, depletion and amortization
|
29,132
|
|
|
26,765
|
|
|
17,733
|
|
Accretion expense
|
131
|
|
|
208
|
|
|
187
|
|
Adjusted
EBITDA
|
$
|
62,129
|
|
|
$
|
59,736
|
|
|
$
|
43,390
|
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the three months ended
September 30, 2017 was $61.9
million and is reconciled to operating cash flow in the
following table (in thousands):
|
Three Months
Ended
|
|
September 30,
2017
|
|
June 30,
2017
|
|
September 30,
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
Net income
|
$
|
17,081
|
|
|
$
|
33,390
|
|
|
$
|
21,139
|
|
Adjustments to
reconcile net income to cash provided by operating
activities:
|
Depreciation, depletion and amortization
|
29,132
|
|
|
26,765
|
|
|
17,733
|
|
Accretion expense
|
131
|
|
|
208
|
|
|
187
|
|
Amortization of non-cash debt related items
|
441
|
|
|
589
|
|
|
810
|
|
Deferred
income tax expense
|
237
|
|
|
323
|
|
|
(62)
|
|
Net
(gain) loss on derivatives, net of settlements
|
12,947
|
|
|
(10,761)
|
|
|
(1,044)
|
|
Loss on
sale of other property and equipment
|
—
|
|
|
62
|
|
|
—
|
|
Non-cash
expense related to equity share-based awards
|
1,219
|
|
|
4,865
|
|
|
608
|
|
Change
in the fair value of liability share-based awards
|
732
|
|
|
1,982
|
|
|
3,371
|
|
Discretionary cash
flow
|
$
|
61,920
|
|
|
$
|
57,423
|
|
|
$
|
42,742
|
|
Changes
in working capital
|
$
|
(7,777)
|
|
|
$
|
(8,968)
|
|
|
$
|
2,927
|
|
Payments
to settle asset retirement obligations
|
(250)
|
|
|
(816)
|
|
|
(576)
|
|
Payments
to settle vested liability share-based awards
|
—
|
|
|
(4,511)
|
|
|
—
|
|
Net cash provided by
operating activities
|
$
|
53,893
|
|
|
$
|
43,128
|
|
|
$
|
45,093
|
|
Callon Petroleum
Company
|
Consolidated
Balance Sheets
|
(in thousands,
except par and per share values and share data)
|
|
|
September 30,
2017
|
|
December 31,
2016
|
ASSETS
|
Unaudited
|
|
|
Current
assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
61,609
|
|
|
$
|
652,993
|
|
Accounts
receivable
|
81,973
|
|
|
69,783
|
|
Fair value of
derivatives
|
3,333
|
|
|
103
|
|
Other current
assets
|
2,583
|
|
|
2,247
|
|
Total current
assets
|
149,498
|
|
|
725,126
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
Evaluated
properties
|
3,283,985
|
|
|
2,754,353
|
|
Less accumulated
depreciation, depletion, amortization and impairment
|
(2,026,809)
|
|
|
(1,947,673)
|
|
Net evaluated oil and
natural gas properties
|
1,257,176
|
|
|
806,680
|
|
Unevaluated
properties
|
1,173,614
|
|
|
668,721
|
|
Total oil and natural
gas properties
|
2,430,790
|
|
|
1,475,401
|
|
Other property and
equipment, net
|
18,626
|
|
|
14,114
|
|
Restricted
investments
|
3,362
|
|
|
3,332
|
|
Deferred financing
costs
|
5,209
|
|
|
3,092
|
|
Fair value of
derivatives
|
1,121
|
|
|
—
|
|
Acquisition
deposit
|
—
|
|
|
46,138
|
|
Prepaid
|
4,650
|
|
|
—
|
|
Other assets,
net
|
827
|
|
|
384
|
|
Total
assets
|
$
|
2,614,083
|
|
|
$
|
2,267,587
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
147,338
|
|
|
$
|
95,577
|
|
Accrued
interest
|
18,375
|
|
|
6,057
|
|
Cash-settleable
restricted stock unit awards
|
4,158
|
|
|
8,919
|
|
Asset retirement
obligations
|
1,841
|
|
|
2,729
|
|
Fair value of
derivatives
|
6,380
|
|
|
18,268
|
|
Total current
liabilities
|
178,092
|
|
|
131,550
|
|
Senior secured
revolving credit facility
|
—
|
|
|
—
|
|
6.125% senior
unsecured notes due 2024, net of unamortized deferred financing
costs
|
595,115
|
|
|
390,219
|
|
Asset retirement
obligations
|
3,163
|
|
|
3,932
|
|
Cash-settleable
restricted stock unit awards
|
2,626
|
|
|
8,071
|
|
Deferred tax
liability
|
1,158
|
|
|
90
|
|
Fair value of
derivatives
|
659
|
|
|
28
|
|
Other long-term
liabilities
|
405
|
|
|
295
|
|
Total
liabilities
|
781,218
|
|
|
534,185
|
|
Commitments and
contingencies
|
|
|
|
Stockholders'
equity:
|
|
|
|
Preferred stock,
series A cumulative, $0.01 par value and $50.00 liquidation
preference, 2,500,000 shares authorized; 1,458,948 shares
outstanding
|
15
|
|
|
15
|
|
Common stock, $0.01
par value, 300,000,000 shares authorized; 201,827,995 and
201,041,320 shares outstanding, respectively
|
2,018
|
|
|
2,010
|
|
Capital in excess of
par value
|
2,179,258
|
|
|
2,171,514
|
|
Accumulated
deficit
|
(348,426)
|
|
|
(440,137)
|
|
Total stockholders'
equity
|
1,832,865
|
|
|
1,733,402
|
|
Total liabilities and
stockholders' equity
|
$
|
2,614,083
|
|
|
$
|
2,267,587
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Operations
|
(Unaudited; in
thousands, except per share data)
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Operating
revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
73,349
|
|
|
$
|
49,095
|
|
|
$
|
218,242
|
|
|
$
|
117,093
|
|
Natural gas
sales
|
11,265
|
|
|
6,832
|
|
|
30,019
|
|
|
14,677
|
|
Total operating
revenues
|
84,614
|
|
|
55,927
|
|
|
248,261
|
|
|
131,770
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Lease operating
expenses
|
11,624
|
|
|
9,961
|
|
|
36,708
|
|
|
24,229
|
|
Production
taxes
|
5,444
|
|
|
3,478
|
|
|
16,168
|
|
|
8,153
|
|
Depreciation,
depletion and amortization
|
28,525
|
|
|
17,303
|
|
|
79,172
|
|
|
49,318
|
|
General and
administrative
|
7,259
|
|
|
7,891
|
|
|
18,894
|
|
|
19,755
|
|
Settled share-based
awards
|
—
|
|
|
—
|
|
|
6,351
|
|
|
—
|
|
Accretion
expense
|
131
|
|
|
187
|
|
|
523
|
|
|
762
|
|
Write-down of oil and
natural gas properties
|
—
|
|
|
—
|
|
|
—
|
|
|
95,788
|
|
Acquisition
expense
|
205
|
|
|
456
|
|
|
3,027
|
|
|
2,410
|
|
Total operating
expenses
|
53,188
|
|
|
39,276
|
|
|
160,843
|
|
|
200,415
|
|
Income (loss) from
operations
|
31,426
|
|
|
16,651
|
|
|
87,418
|
|
|
(68,645)
|
|
Other (income)
expenses:
|
|
|
|
|
|
|
|
Interest expense, net
of capitalized amounts
|
444
|
|
|
831
|
|
|
1,698
|
|
|
10,502
|
|
(Gain) loss on
derivative contracts
|
14,162
|
|
|
(5,135)
|
|
|
(11,636)
|
|
|
11,281
|
|
Other
income
|
(498)
|
|
|
(122)
|
|
|
(1,270)
|
|
|
(299)
|
|
Total other (income)
expense
|
14,108
|
|
|
(4,426)
|
|
|
(11,208)
|
|
|
21,484
|
|
Income (loss) before
income taxes
|
17,318
|
|
|
21,077
|
|
|
98,626
|
|
|
(90,129)
|
|
Income tax (benefit)
expense
|
237
|
|
|
(62)
|
|
|
1,026
|
|
|
(62)
|
|
Net income
(loss)
|
17,081
|
|
|
21,139
|
|
|
97,600
|
|
|
(90,067)
|
|
Preferred stock
dividends
|
(1,824)
|
|
|
(1,824)
|
|
|
(5,471)
|
|
|
(5,471)
|
|
Income (loss)
available to common stockholders
|
$
|
15,257
|
|
|
$
|
19,315
|
|
|
$
|
92,129
|
|
|
$
|
(95,538)
|
|
Income (loss) per
common share:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.08
|
|
|
$
|
0.14
|
|
|
$
|
0.46
|
|
|
$
|
(0.85)
|
|
Diluted
|
$
|
0.08
|
|
|
$
|
0.14
|
|
|
$
|
0.46
|
|
|
$
|
(0.85)
|
|
Shares used in
computing income (loss) per common share:
|
|
|
|
|
|
|
Basic
|
201,827
|
|
|
136,983
|
|
|
201,422
|
|
|
112,925
|
|
Diluted
|
202,337
|
|
|
137,483
|
|
|
201,995
|
|
|
112,925
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
17,081
|
|
|
$
|
21,139
|
|
|
$
|
97,600
|
|
|
$
|
(90,067)
|
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
Depreciation,
depletion and amortization
|
29,132
|
|
|
17,733
|
|
|
80,829
|
|
|
50,560
|
|
Write-down of oil and
natural gas properties
|
—
|
|
|
—
|
|
|
—
|
|
|
95,788
|
|
Accretion
expense
|
131
|
|
|
187
|
|
|
523
|
|
|
762
|
|
Amortization of
non-cash debt related items
|
441
|
|
|
810
|
|
|
1,695
|
|
|
2,371
|
|
Deferred income tax
(benefit) expense
|
237
|
|
|
(62)
|
|
|
1,026
|
|
|
(62)
|
|
Net (gain) loss on
derivatives, net of settlements
|
12,947
|
|
|
(1,044)
|
|
|
(15,608)
|
|
|
27,105
|
|
Loss on sale of other
property and equipment
|
—
|
|
|
—
|
|
|
62
|
|
|
—
|
|
Non-cash expense
related to equity share-based awards
|
1,219
|
|
|
778
|
|
|
7,014
|
|
|
1,954
|
|
Change in the fair
value of liability share-based awards
|
732
|
|
|
3,371
|
|
|
2,423
|
|
|
6,045
|
|
Payments to settle
asset retirement obligations
|
(250)
|
|
|
(576)
|
|
|
(1,831)
|
|
|
(895)
|
|
Changes in current
assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
(4,338)
|
|
|
(11,608)
|
|
|
(12,148)
|
|
|
(16,444)
|
|
Other current
assets
|
(38)
|
|
|
54
|
|
|
(336)
|
|
|
(251)
|
|
Current
liabilities
|
1,854
|
|
|
15,702
|
|
|
7,534
|
|
|
19,815
|
|
Change in other
long-term liabilities
|
1
|
|
|
—
|
|
|
121
|
|
|
86
|
|
Change in long-term
prepaid
|
(4,650)
|
|
|
—
|
|
|
(4,650)
|
|
|
—
|
|
Change in other
assets, net
|
(606)
|
|
|
(1,221)
|
|
|
(1,376)
|
|
|
(1,671)
|
|
Payments to settle
vested liability share-based awards
|
—
|
|
|
—
|
|
|
(13,173)
|
|
|
(10,300)
|
|
Net cash provided
by operating activities
|
53,893
|
|
|
45,263
|
|
|
149,705
|
|
|
84,796
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
(121,128)
|
|
|
(47,418)
|
|
|
(267,218)
|
|
|
(122,698)
|
|
Acquisitions
|
(8,015)
|
|
|
(18,033)
|
|
|
(714,504)
|
|
|
(302,057)
|
|
Acquisition
deposit
|
—
|
|
|
(32,700)
|
|
|
46,138
|
|
|
(32,700)
|
|
Proceeds from sales
of mineral interests and equipment
|
—
|
|
|
(708)
|
|
|
—
|
|
|
22,923
|
|
Net cash used in
investing activities
|
(129,143)
|
|
|
(98,859)
|
|
|
(935,584)
|
|
|
(434,532)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
—
|
|
|
74,000
|
|
|
—
|
|
|
217,000
|
|
Payments on senior
secured revolving credit facility
|
—
|
|
|
(114,000)
|
|
|
—
|
|
|
(257,000)
|
|
Issuance of 6.125%
senior unsecured notes due 2024
|
—
|
|
|
—
|
|
|
200,000
|
|
|
—
|
|
Premium on the
issuance of 6.125% senior unsecured notes due 2024
|
—
|
|
|
—
|
|
|
8,250
|
|
|
—
|
|
Issuance of common
stock
|
—
|
|
|
421,908
|
|
|
—
|
|
|
722,715
|
|
Payment of preferred
stock dividends
|
(1,824)
|
|
|
(1,824)
|
|
|
(5,471)
|
|
|
(5,471)
|
|
Payment of deferred
financing costs
|
(401)
|
|
|
(640)
|
|
|
(7,166)
|
|
|
(640)
|
|
Tax withholdings
related to restricted stock units
|
(65)
|
|
|
(170)
|
|
|
(1,118)
|
|
|
(2,207)
|
|
Net cash provided
by financing activities
|
(2,290)
|
|
|
379,274
|
|
|
194,495
|
|
|
674,397
|
|
Net change in cash
and cash equivalents
|
(77,540)
|
|
|
325,678
|
|
|
(591,384)
|
|
|
324,661
|
|
Balance, beginning of
period
|
139,149
|
|
|
207
|
|
|
652,993
|
|
|
1,224
|
|
Balance, end of
period
|
$
|
61,609
|
|
|
$
|
325,885
|
|
|
$
|
61,609
|
|
|
$
|
325,885
|
|
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as
"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 SEC
filings and posted on our website.
- Callon believes that the non-GAAP measure of discretionary cash
flow is useful as an indicator of an oil and natural gas
exploration and production company's ability to internally fund
exploration and development activities and to service or incur
additional debt. The Company also 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 may not relate to the period in which the operating
activities occurred. Discretionary cash flow is calculated using
net income (loss) adjusted for certain items including
depreciation, depletion and amortization, the impact of financial
derivatives (including the mark-to-market effects, net of cash
settlements and premiums paid or received related to our financial
derivatives), remaining asset retirement obligations related to our
divested offshore properties, restructuring and other non-recurring
costs, deferred income taxes and other non-cash income items.
- Callon believes that the non-GAAP measure of Adjusted G&A
is useful to investors because it provides readers with a
meaningful measure of our recurring G&A expense and provides
for greater comparability period-over-period. The table above
details all adjustments to G&A on a GAAP basis to arrive at
Adjusted G&A.
- We believe that the non-GAAP measure of Adjusted Income
available to common shareholders ("Adjusted Income") and Adjusted
Income per diluted share are useful to investors because they
provide readers with a meaningful measure of our profitability
before recording certain items whose timing or amount cannot be
reasonably determined. These measures exclude the net of tax
effects of certain non-recurring items and non-cash valuation
adjustments, which are detailed in the reconciliation provided
above. Prior to being tax-effected and excluded, the amounts
reflected in the determination of Adjusted Income and Adjusted
Income per diluted share above were computed in accordance with
GAAP.
- We calculate Adjusted Earnings before Interest, Income Taxes,
Depreciation, Depletion and Amortization ("Adjusted EBITDA") as
Adjusted Income plus interest expense, income tax expense (benefit)
and depreciation, depletion and amortization expense. 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, we believe 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 we present may not be
comparable to similarly titled measures of other companies.
- We believe 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 account for derivative
contracts and hedges and include their effects in revenue. We
believe Adjusted Total Revenue is also useful to investors as a
measure of the actual cash inflows generated during the
period.
Earnings Call Information
The Company will host a conference call on Tuesday,
November 7, 2017, to discuss third quarter 2017 financial and
operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Tuesday, November 7,
2017, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)
|
Webcast:
|
Select "IR Calendar"
under the "Investors" section of the website:
www.callon.com.
|
Presentation
Slides:
|
Select
"Presentations" under the "Investors" section of the website:
www.callon.com.
|
Alternatively, you may join by telephone using the following
numbers:
Toll Free:
|
1-888-317-6003
|
Canada Toll
Free:
|
1-866-284-3684
|
International:
|
1-412-317-6061
|
Access
code:
|
6326656
|
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 energy company
focused on the acquisition, development, exploration, and operation
of oil and natural gas properties in the Permian Basin in
West Texas.
This news release is posted on the Company's website at
www.callon.com and will be archived there for subsequent review
under the "News" link on the top of the homepage.
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 2017 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"
and words of similar meaning. These statements reflect the
Company's current views with respect to future events and financial
performance. 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. 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, ability to drill and complete wells,
operational, regulatory and environment risks, our ability to
finance our activities and other risks more fully discussed in our
filings with the Securities and Exchange Commission, including our
Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q,
available on our website or the SEC's website
at www.sec.gov.
For further information contact:
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-800-451-1294
|
|
|
i)
|
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-third-quarter-2017-results-300550288.html
SOURCE Callon Petroleum Company