NATCHEZ, Miss., Aug. 2,
2017 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE)
("Callon" or the "Company") today reported results of operations
for the three months ended June 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 second quarter of
2017, and other recent data points include:
- Completed delineation of Wolfcamp A zone across aerial extent
of Howard County position
- Successful Lower Spraberry well density test leading to 15%
uplift in Monarch inventory
- Deployed 4th rig to Delaware basin and began operated drilling
program at Spur in July
- Increased production by 9% quarter over quarter, driven
primarily by higher oil mix (79%)
- Reduced lease operating expense per BOE by 15% from previous
quarter
- Increased borrowing base to $650
million with a company-elected commitment of $500 million
- Raised $200 million in a senior
notes offering that priced at a yield-to-worst of 5.2%
- Revising guidance to lower lease operating expense per unit and
increase the oil mix for fiscal year 2017
"During the quarter we delivered double-digit oil production
growth coupled with a double-digit reduction in lease operating
expense," commented Joe Gatto,
President and Chief Executive Officer. "In addition, we made
important strides in the delineation of our asset base, including
the extension of our program development into the central portion
of Howard County and the completion of successful Lower Spraberry
density spacing tests in our Monarch area. We also recently added a
dedicated rig to our Spur area in the Delaware Basin in July and are now running
four rigs that will be active across all four of our operating
areas during the second half of 2017. In keeping with our strategy
of sustainable growth and financial discipline, we are
well-positioned to add a fifth rig in early 2018 and achieve our
2018 target exit rate goal of 40,000 BOE per day."
Operations Update
At June 30, 2017, we had 205 gross (151.1 net) horizontal
wells producing from seven established flow units in the Permian
Basin. Net daily production for the three months ended
June 30, 2017 grew approximately 65% to 22.2 thousand barrels
of oil equivalent per day ("MBOE/d") (approximately 79% oil) as
compared to the same period of 2016. Sequentially, we grew
production by approximately 9% compared to the first quarter of
2017, with a corresponding 11% sequential increase in our oil
volumes.
For the three months ended June 30, 2017, we operated three
horizontal drilling rigs, drilling 14 gross (10.7 net) horizontal
wells in the Monarch, Ranger and WildHorse areas. We placed a
combined 14 gross (9.7 net) horizontal wells on production in the
quarter in the Monarch, Spur and WildHorse areas. In July 2017, we moved from a three-rig program to a
four-rig program with the arrival of our first operated rig in the
Delaware basin allocated to our
Spur area. In addition, we recently added a second dedicated
completion crew to account for our ramp in activity during the
second half of 2017.
In the Midland Basin, we completed delineation of the Wolfcamp A
across our Howard County position with recent well results tracking
the 1 million barrels of oil equivalent ("MMBOE") type curve.
Infrastructure development in the region continues to drive down
lease operating expense per BOE and is expected to enhance early
time peak fluid capacity, leading to improved de-watering of the
formation and early time increases in oil cuts. Recent Lower
Spraberry completions in Howard County continue to produce with
shallow declines and upcoming wells in the formation are expected
to benefit from new completion designs that focus on high density,
near-wellbore design.
Production results and pressure data from the Monarch density
pilot program support the establishment of a new 13 well per
section stack-and-stagger model for the Lower Spraberry. This
higher density well pattern increases the Lower Spraberry inventory
at Monarch by approximately 15%. The inventory for the Lower
Spraberry at Monarch now equates to more than 10 years of drilling
inventory for a full-time rig line.
During the second quarter, we fracture stimulated our first two
Lower Wolfcamp B wells in Reagan County since 2015. These
wells are currently flowing back and are expected to reach peak
rate during the third quarter. Additional drilling activity
is currently planned during the second half of 2017 at Ranger,
inclusive of a Wolfcamp C test well.
In the Delaware basin, the two
wells acquired from the previous operator are tracking the
respective acquisition type curves (1.6 MMBOE for the Wolfcamp A
and 900 MBOE for the Wolfcamp B, both normalized for a 7,500 foot
lateral). With a full-time rig now dedicated to Spur,
upcoming wells will incorporate changes to both completion design
and optimized landing zone for upcoming drilling in multiple
intervals within the Wolfcamp formation.
On June 5, 2017, we completed the
acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, contiguous to the Spur
operating area, for total cash consideration of $52.5 million, excluding customary purchase price
adjustments. The purchase price was funded with available
cash-on-hand and the proceeds from the recent $200 million senior notes add-on offering.
Capital Expenditures
For the three months ended June 30, 2017, we incurred
$64.0 million in cash operational
capital expenditures compared to $55.5
million in the first quarter of 2017. Total capital
expenditures, inclusive of capitalized expenses, are detailed below
on an accrual and cash basis (in thousands):
|
|
Three Months Ended
June 30, 2017
|
|
|
Operational
|
|
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
|
Capital
|
|
Other
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
Cash basis
(b)
|
|
$
|
63,999
|
|
|
$
|
1,382
|
|
|
$
|
10,791
|
|
|
$
|
3,764
|
|
|
$
|
79,936
|
|
Timing adjustments
(c)
|
|
18,082
|
|
|
—
|
|
|
(2,858)
|
|
|
—
|
|
|
15,224
|
|
Non-cash
items
|
|
—
|
|
|
—
|
|
|
—
|
|
|
408
|
|
|
408
|
|
Accrual
(GAAP) basis
|
|
$
|
82,081
|
|
|
$
|
1,382
|
|
|
$
|
7,933
|
|
|
$
|
4,172
|
|
|
$
|
95,568
|
|
|
|
(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
|
|
|
June 30,
2017
|
|
March 31,
2017
|
|
June 30,
2016
|
Net
production:
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
1,596
|
|
|
1,434
|
|
|
948
|
|
Natural gas
(MMcf)
|
|
2,550
|
|
|
2,422
|
|
|
1,658
|
|
Total production
(MBOE)
|
|
2,021
|
|
|
1,838
|
|
|
1,224
|
|
Average daily
production (BOE/d)
|
|
22,209
|
|
|
20,422
|
|
|
13,451
|
|
% oil
(BOE basis)
|
|
79
|
%
|
|
78
|
%
|
|
77
|
%
|
Oil and natural
gas revenues (in thousands):
|
|
|
|
|
|
|
Oil
revenue
|
|
$
|
72,885
|
|
|
$
|
72,008
|
|
|
$
|
40,555
|
|
Natural
gas revenue
|
|
9,398
|
|
|
9,355
|
|
|
4,590
|
|
Total
revenue
|
|
82,283
|
|
|
81,363
|
|
|
45,145
|
|
Impact
of cash-settled derivatives
|
|
(267)
|
|
|
(2,491)
|
|
|
4,017
|
|
Adjusted Total Revenue
(i)
|
|
$
|
82,016
|
|
|
$
|
78,872
|
|
|
$
|
49,162
|
|
Average realized
sales price:
|
|
|
|
|
|
|
Oil
(Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
45.67
|
|
|
$
|
50.21
|
|
|
$
|
42.78
|
|
Oil
(Bbl) (including impact of cash settled derivatives)
|
|
45.47
|
|
|
48.45
|
|
|
46.69
|
|
Natural
gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
3.69
|
|
|
$
|
3.86
|
|
|
$
|
2.77
|
|
Natural
gas (Mcf) (including impact of cash settled derivatives)
|
|
3.70
|
|
|
3.88
|
|
|
2.96
|
|
Total
(BOE) (excluding impact of cash settled derivatives)
|
|
$
|
40.71
|
|
|
$
|
44.27
|
|
|
$
|
36.88
|
|
Total
(BOE) (including impact of cash settled derivatives)
|
|
40.58
|
|
|
42.91
|
|
|
40.17
|
|
Additional per BOE
data:
|
|
|
|
|
|
|
Sales
price (excluding impact of cash settled derivatives)
|
|
$
|
40.71
|
|
|
$
|
44.27
|
|
|
$
|
36.88
|
|
Lease operating
expense (excluding gathering and treating expense)
|
|
5.56
|
|
|
6.61
|
|
|
5.70
|
|
Gathering and treating
expense
|
|
0.45
|
|
|
0.43
|
|
|
0.27
|
|
Production
taxes
|
|
2.38
|
|
|
3.21
|
|
|
2.01
|
|
Operating margin
|
|
$
|
32.32
|
|
|
$
|
34.02
|
|
|
$
|
28.90
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
$
|
12.97
|
|
|
$
|
13.29
|
|
|
$
|
13.31
|
|
Adjusted
G&A (a)
|
|
|
|
|
|
|
Cash component
(b)
|
|
$
|
2.67
|
|
|
$
|
2.43
|
|
|
$
|
2.92
|
|
Non-cash
component
|
|
0.53
|
|
|
0.57
|
|
|
0.63
|
|
|
|
(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 June 30,
2017, Callon reported total revenue of $82.3
million and total revenue including cash-settled derivatives
("Adjusted Total Revenue," a non-GAAP financial
measure(i)) of $82.0
million, including the impact of a $0.3 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 22.2 MBOE/d compared
to average daily production of 20.4 MBOE/d in the first quarter of
2017. Average realized prices, including and excluding the effects
of hedging, are detailed below.
Hedging impacts. For the quarter ended June 30,
2017, Callon recognized the following hedging-related items (in
thousands, except per unit data):
|
In
Thousands
|
|
Per
Unit
|
Oil
derivatives
|
|
|
|
Net gain (loss) on
settlements
|
$
|
(315)
|
|
|
$
|
(0.20)
|
|
Net gain (loss) on
fair value adjustments
|
10,128
|
|
|
|
Total gain (loss) on
oil derivatives
|
$
|
9,813
|
|
|
|
Natural gas
derivatives
|
|
|
|
Net gain on
settlements
|
$
|
48
|
|
|
$
|
0.01
|
|
Net gain (loss) on
fair value adjustments
|
633
|
|
|
|
Total gain (loss) on
natural gas derivatives
|
$
|
681
|
|
|
|
Total oil &
natural gas derivatives
|
|
|
|
Net loss on
settlements
|
$
|
(267)
|
|
|
$
|
(0.13)
|
|
Net gain on fair
value adjustments
|
10,761
|
|
|
|
Total
gain on total oil & natural gas derivatives
|
$
|
10,494
|
|
|
|
Lease Operating Expenses, including workover and gathering
expense ("LOE"). LOE per BOE for the three months ended
June 30, 2017 was $6.01 per BOE,
compared to LOE of $7.04 per BOE in
the first quarter of 2017. The decrease in this metric was related
to early-day benefits from infrastructure projects materializing
throughout the quarter as well as an increase in production
volumes.
Production Taxes, including ad valorem taxes. Production
taxes were $2.38 per BOE for the
three months ended June 30, 2017, representing approximately
5.9% of total revenue before the impact of derivative
settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
June 30, 2017 was $12.97 per BOE
compared to $13.29 per BOE in the
first quarter of 2017. The decrease on a per unit basis was
primarily attributable to greater increases in the estimated total
proved reserve base as compared to the increases in our depreciable
asset base and assumed future development costs related to
undeveloped proved reserves.
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 $3.20 per BOE, for
the three months ended June 30, 2017 compared to $5.5 million, or $3.00 per BOE, for the first quarter of 2017. The
cash component of Adjusted G&A was $5.4
million, or $2.67 per BOE, for
the three months ended June 30, 2017 compared to $4.5 million, or $2.43 per BOE, for the first quarter of 2017.
For the three months ended June 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 June 30, 2017
|
Total G&A
expense
|
$
|
6,430
|
|
Less:
Early retirement expenses
|
(444)
|
|
Less:
Early retirement expenses related to share-based
compensation
|
(81)
|
|
Less:
Change in the fair value of liability share-based awards
(non-cash)
|
567
|
|
Adjusted G&A –
total
|
6,472
|
|
Less:
Restricted stock share-based compensation (non-cash)
|
(966)
|
|
Less:
Corporate depreciation & amortization (non-cash)
|
(114)
|
|
Adjusted G&A –
cash component
|
$
|
5,392
|
|
Settled share-based awards. In June 2017, the Company settled the outstanding
share-based award agreements of its former Chief Executive Officer,
resulting in a payment of $6.4
million.
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 $0.3 million for the three months ended
June 30, 2017. At June 30, 2017 we had a valuation
allowance of $115.9 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
$11.2 million (or $0.06 per diluted share) for the quarter as if
the valuation allowance did not exist.
2017 Guidance Update
|
Third
Quarter
|
|
Full
Year
|
|
2017
Guidance
|
|
2017
Guidance
|
Total production
(BOE/d)
|
23,000 -
25,000
|
|
22,500 -
25,500
|
% oil
|
77 %
|
|
78 %
|
Income Statement
Expenses (per BOE)
|
|
|
|
LOE, including
workovers
|
$6.00 -
$6.50
|
|
$5.75 -
$6.25
|
Gathering and
treating
|
$0.40 -
$0.50
|
|
$0.40 -
$0.50
|
Production taxes,
including ad valorem (% unhedged revenue)
|
7%
|
|
7%
|
Adjusted
G&A: cash component (a)
|
$2.25 -
$2.50
|
|
$2.00 -
$2.50
|
Adjusted
G&A: non-cash component (b)
|
$0.50 -
$0.75
|
|
$0.50 -
$1.00
|
Interest
expense (c)
|
$0.00
|
|
$0.00
|
Effective income tax
rate
|
0%
|
|
0%
|
Capital
expenditures ($MM, accrual basis)
|
|
|
|
Operational
(d)
|
$110 -
$130
|
|
$350
|
Capitalized expenses
(cash component)
|
$12 - $17
|
|
$40 - $45
|
Net operated
horizontal well completions
|
|
|
|
Midland
Basin
|
~10
|
|
~39
|
Delaware
Basin
|
~1
|
|
~3
|
|
|
(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 second 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)
|
368
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Swap
|
$
|
44.50
|
|
|
$
|
—
|
|
Short put
option
|
$
|
30.00
|
|
|
$
|
—
|
|
Swap
contracts
|
|
|
|
Total volume
(MBbls)
|
368
|
|
|
730
|
|
Weighted average
price per Bbl
|
$
|
45.74
|
|
|
$
|
50.03
|
|
Deferred premium
put spread option
|
|
|
|
Total volume
(MBbls)
|
506
|
|
|
—
|
|
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)
|
681
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Ceiling (short
call)
|
$
|
58.19
|
|
|
$
|
—
|
|
Floor (long
put)
|
$
|
47.50
|
|
|
$
|
—
|
|
Call option
contracts
|
|
|
|
Total volume
(MBbls)
|
338
|
|
|
—
|
|
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)
|
1,104
|
|
|
2,738
|
|
Weighted average
price per Bbl
|
$
|
(0.52)
|
|
|
$
|
(1.03)
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
736
|
|
|
—
|
|
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)
|
1,224
|
|
|
720
|
|
Weighted average
price per MMBtu
|
|
|
|
Ceiling (short
call option)
|
$
|
3.74
|
|
|
$
|
3.84
|
|
Floor (long
put option)
|
$
|
3.16
|
|
|
$
|
3.40
|
|
Swap
contracts
|
|
|
|
Total volume
(BBtu)
|
492
|
|
|
—
|
|
Weighted average
price per MMBtu
|
$
|
3.39
|
|
|
$
|
—
|
|
Income (Loss) Available to Common Shareholders. The
Company reported net income available to common shareholders of
$31.6 million for the three months
ended June 30, 2017 and Adjusted Income available to common
shareholders of $17.2 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
|
|
June 30,
2017
|
|
March 31,
2017
|
|
June 30,
2016
|
Income (loss)
available to common stockholders
|
$
|
31,566
|
|
|
$
|
45,305
|
|
|
$
|
(71,920)
|
|
Change
in valuation allowance
|
(11,194)
|
|
|
(13,119)
|
|
|
24,409
|
|
Write-down of oil and natural gas properties
|
—
|
|
|
—
|
|
|
39,658
|
|
Net
(gain) loss on derivatives, net of settlements
|
(6,995)
|
|
|
(11,566)
|
|
|
12,676
|
|
Change
in the fair value of share-based awards
|
(315)
|
|
|
(189)
|
|
|
1,277
|
|
Settled
share-based awards
|
4,128
|
|
|
—
|
|
|
—
|
|
Withdrawn proxy contest expenses
|
—
|
|
|
—
|
|
|
2
|
|
Adjusted
Income
|
$
|
17,190
|
|
|
$
|
20,431
|
|
|
$
|
6,102
|
|
Adjusted Income per
fully diluted common share
|
$
|
0.09
|
|
|
$
|
0.10
|
|
|
$
|
0.05
|
|
|
|
Three Months
Ended
|
|
June 30,
2017
|
|
March 31,
2017
|
|
June 30,
2016
|
Net income
(loss)
|
$
|
33,390
|
|
|
$
|
47,129
|
|
|
$
|
(70,097)
|
|
Write-down of oil and natural gas properties
|
—
|
|
|
—
|
|
|
61,012
|
|
Net
(gain) loss on derivatives, net of settlements
|
(10,761)
|
|
|
(17,794)
|
|
|
19,501
|
|
Non-cash
stock-based compensation expense
|
499
|
|
|
639
|
|
|
2,628
|
|
Settled
share-based awards
|
6,351
|
|
|
—
|
|
|
—
|
|
Withdrawn proxy contest expenses
|
—
|
|
|
—
|
|
|
3
|
|
Acquisition expense
|
2,373
|
|
|
450
|
|
|
1,906
|
|
Income
tax expense
|
322
|
|
|
466
|
|
|
—
|
|
Interest
expense
|
589
|
|
|
665
|
|
|
4,180
|
|
Depreciation, depletion and amortization
|
26,765
|
|
|
24,932
|
|
|
16,698
|
|
Accretion expense
|
208
|
|
|
184
|
|
|
395
|
|
Adjusted
EBITDA
|
$
|
59,736
|
|
|
$
|
56,671
|
|
|
$
|
36,226
|
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the three months ended
June 30, 2017 was $57.4 million
and is reconciled to operating cash flow in the following table (in
thousands):
|
Three Months
Ended
|
|
June 30,
2017
|
|
March 31,
2017
|
|
June 30,
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
Net income
(loss)
|
$
|
33,390
|
|
|
$
|
47,129
|
|
|
$
|
(70,097)
|
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
26,765
|
|
|
24,932
|
|
|
16,698
|
|
Write-down of oil and natural gas properties
|
—
|
|
|
—
|
|
|
61,012
|
|
Accretion expense
|
208
|
|
|
184
|
|
|
395
|
|
Amortization of non-cash debt related items
|
589
|
|
|
665
|
|
|
780
|
|
Deferred
income tax expense
|
323
|
|
|
466
|
|
|
—
|
|
Net
(gain) loss on derivatives, net of settlements
|
(10,761)
|
|
|
(17,794)
|
|
|
19,501
|
|
Loss on
sale of other property and equipment
|
62
|
|
|
—
|
|
|
—
|
|
Non-cash
expense related to equity share-based awards
|
4,865
|
|
|
930
|
|
|
(1,253)
|
|
Change
in the fair value of liability share-based awards
|
1,982
|
|
|
(291)
|
|
|
1,965
|
|
Discretionary cash
flow
|
$
|
57,423
|
|
|
$
|
56,221
|
|
|
$
|
29,001
|
|
Changes
in working capital
|
$
|
(8,968)
|
|
|
$
|
5,890
|
|
|
$
|
(6,974)
|
|
Payments
to settle asset retirement obligations
|
(816)
|
|
|
(765)
|
|
|
(158)
|
|
Payments
to settle vested liability share-based awards
|
(4,511)
|
|
|
(8,662)
|
|
|
(493)
|
|
Net cash provided by
operating activities
|
$
|
43,128
|
|
|
$
|
52,684
|
|
|
$
|
21,376
|
|
Callon Petroleum
Company
|
Consolidated
Balance Sheets
|
(in thousands,
except par and per share values and share data)
|
|
|
June 30,
2017
|
|
December 31,
2016
|
ASSETS
|
Unaudited
|
|
|
Current
assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
139,149
|
|
|
$
|
652,993
|
|
Accounts
receivable
|
77,635
|
|
|
69,783
|
|
Fair value of
derivatives
|
9,241
|
|
|
103
|
|
Other current
assets
|
2,545
|
|
|
2,247
|
|
Total current
assets
|
228,570
|
|
|
725,126
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
Evaluated
properties
|
3,125,238
|
|
|
2,754,353
|
|
Less accumulated
depreciation, depletion, amortization and impairment
|
(1,998,294)
|
|
|
(1,947,673)
|
|
Net evaluated oil and
natural gas properties
|
1,126,944
|
|
|
806,680
|
|
Unevaluated
properties
|
1,194,999
|
|
|
668,721
|
|
Total oil and natural
gas properties
|
2,321,943
|
|
|
1,475,401
|
|
Other property and
equipment, net
|
18,071
|
|
|
14,114
|
|
Restricted
investments
|
3,348
|
|
|
3,332
|
|
Deferred financing
costs
|
5,273
|
|
|
3,092
|
|
Fair value of
derivatives
|
3,804
|
|
|
—
|
|
Acquisition
deposit
|
—
|
|
|
46,138
|
|
Other assets,
net
|
655
|
|
|
384
|
|
Total
assets
|
$
|
2,581,664
|
|
|
$
|
2,267,587
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
144,958
|
|
|
$
|
95,577
|
|
Accrued
interest
|
9,256
|
|
|
6,057
|
|
Cash-settleable
restricted stock unit awards
|
3,650
|
|
|
8,919
|
|
Asset retirement
obligations
|
1,767
|
|
|
2,729
|
|
Fair value of
derivatives
|
2,243
|
|
|
18,268
|
|
Total current
liabilities
|
161,874
|
|
|
131,550
|
|
Senior secured
revolving credit facility
|
—
|
|
|
—
|
|
6.125% senior
unsecured notes due 2024, net of unamortized deferred financing
costs
|
595,138
|
|
|
390,219
|
|
Asset retirement
obligations
|
5,031
|
|
|
3,932
|
|
Cash-settleable
restricted stock unit awards
|
1,957
|
|
|
8,071
|
|
Deferred tax
liability
|
921
|
|
|
90
|
|
Fair value of
derivatives
|
441
|
|
|
28
|
|
Other long-term
liabilities
|
405
|
|
|
295
|
|
Total
liabilities
|
765,767
|
|
|
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 and 1,458,948
shares outstanding, respectively
|
15
|
|
|
15
|
|
Common stock, $0.01
par value, 300,000,000 and 300,000,000 shares authorized;
201,806,900 and 201,041,320 shares outstanding,
respectively
|
2,018
|
|
|
2,010
|
|
Capital in excess of
par value
|
2,177,547
|
|
|
2,171,514
|
|
Accumulated
deficit
|
(363,683)
|
|
|
(440,137)
|
|
Total stockholders'
equity
|
1,815,897
|
|
|
1,733,402
|
|
Total liabilities and
stockholders' equity
|
$
|
2,581,664
|
|
|
$
|
2,267,587
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Operations
|
(Unaudited; in
thousands, except per share data)
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Operating
revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
72,885
|
|
|
$
|
40,555
|
|
|
$
|
144,893
|
|
|
$
|
67,998
|
|
Natural gas
sales
|
9,398
|
|
|
4,590
|
|
|
18,754
|
|
|
7,845
|
|
Total operating
revenues
|
82,283
|
|
|
45,145
|
|
|
163,647
|
|
|
75,843
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Lease operating
expenses
|
12,145
|
|
|
7,311
|
|
|
25,084
|
|
|
14,268
|
|
Production
taxes
|
4,820
|
|
|
2,455
|
|
|
10,723
|
|
|
4,675
|
|
Depreciation,
depletion and amortization
|
26,213
|
|
|
16,293
|
|
|
50,646
|
|
|
32,015
|
|
General and
administrative
|
6,430
|
|
|
6,302
|
|
|
11,636
|
|
|
11,864
|
|
Settled share-based
awards
|
6,351
|
|
|
—
|
|
|
6,351
|
|
|
—
|
|
Accretion
expense
|
208
|
|
|
395
|
|
|
392
|
|
|
575
|
|
Write-down of oil and
natural gas properties
|
—
|
|
|
61,012
|
|
|
—
|
|
|
95,788
|
|
Acquisition
expense
|
2,373
|
|
|
1,906
|
|
|
2,822
|
|
|
1,954
|
|
Total operating
expenses
|
58,540
|
|
|
95,674
|
|
|
107,654
|
|
|
161,139
|
|
Income (loss) from
operations
|
23,743
|
|
|
(50,529)
|
|
|
55,993
|
|
|
(85,296)
|
|
Other (income)
expenses:
|
|
|
|
|
|
|
|
Interest expense, net
of capitalized amounts
|
589
|
|
|
4,180
|
|
|
1,254
|
|
|
9,671
|
|
(Gain) loss on
derivative contracts
|
(10,494)
|
|
|
15,484
|
|
|
(25,797)
|
|
|
16,416
|
|
Other
income
|
(64)
|
|
|
(96)
|
|
|
(772)
|
|
|
(177)
|
|
Total other (income)
expense
|
(9,969)
|
|
|
19,568
|
|
|
(25,315)
|
|
|
25,910
|
|
Income (loss) before
income taxes
|
33,712
|
|
|
(70,097)
|
|
|
81,308
|
|
|
(111,206)
|
|
Income tax
expense
|
322
|
|
|
—
|
|
|
789
|
|
|
—
|
|
Net income
(loss)
|
33,390
|
|
|
(70,097)
|
|
|
80,519
|
|
|
(111,206)
|
|
Preferred stock
dividends
|
(1,824)
|
|
|
(1,823)
|
|
|
(3,647)
|
|
|
(3,647)
|
|
Income (loss)
available to common stockholders
|
$
|
31,566
|
|
|
$
|
(71,920)
|
|
|
$
|
76,872
|
|
|
$
|
(114,853)
|
|
Income (loss) per
common share:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.16
|
|
|
$
|
(0.61)
|
|
|
$
|
0.38
|
|
|
$
|
(1.14)
|
|
Diluted
|
$
|
0.16
|
|
|
$
|
(0.61)
|
|
|
$
|
0.38
|
|
|
$
|
(1.14)
|
|
Shares used in
computing income (loss) per common share:
|
|
|
|
|
|
|
Basic
|
201,386
|
|
|
118,209
|
|
|
201,220
|
|
|
100,895
|
|
Diluted
|
201,905
|
|
|
118,209
|
|
|
201,823
|
|
|
100,895
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
33,390
|
|
|
$
|
(70,097)
|
|
|
$
|
80,519
|
|
|
$
|
(111,206)
|
|
Adjustments to
reconcile net income to cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
26,765
|
|
|
16,698
|
|
|
51,697
|
|
|
32,827
|
|
Write-down of oil and
natural gas properties
|
—
|
|
|
61,012
|
|
|
—
|
|
|
95,788
|
|
Accretion
expense
|
208
|
|
|
395
|
|
|
392
|
|
|
575
|
|
Amortization of
non-cash debt related items
|
589
|
|
|
780
|
|
|
1,254
|
|
|
1,561
|
|
Deferred income tax
expense
|
323
|
|
|
—
|
|
|
789
|
|
|
—
|
|
Net (gain) loss on
derivatives, net of settlements
|
(10,761)
|
|
|
19,501
|
|
|
(28,555)
|
|
|
28,149
|
|
Loss on sale of other
property and equipment
|
62
|
|
|
—
|
|
|
62
|
|
|
—
|
|
Non-cash expense
related to equity share-based awards
|
4,865
|
|
|
665
|
|
|
5,795
|
|
|
1,177
|
|
Change in the fair
value of liability share-based awards
|
1,982
|
|
|
1,965
|
|
|
1,691
|
|
|
2,674
|
|
Payments to settle
asset retirement obligations
|
(816)
|
|
|
(158)
|
|
|
(1,581)
|
|
|
(319)
|
|
Changes in current
assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
(3,744)
|
|
|
(10,777)
|
|
|
(7,810)
|
|
|
(4,836)
|
|
Other current
assets
|
(874)
|
|
|
(885)
|
|
|
(298)
|
|
|
(305)
|
|
Current
liabilities
|
(4,223)
|
|
|
4,830
|
|
|
5,680
|
|
|
4,113
|
|
Change in other
long-term liabilities
|
120
|
|
|
75
|
|
|
120
|
|
|
86
|
|
Change in other
assets, net
|
(247)
|
|
|
(217)
|
|
|
(770)
|
|
|
(450)
|
|
Payments to settle
vested liability share-based awards
|
(4,511)
|
|
|
(493)
|
|
|
(13,173)
|
|
|
(10,300)
|
|
Net cash provided by operating
activities
|
43,128
|
|
|
23,294
|
|
|
95,812
|
|
|
39,534
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
(79,936)
|
|
|
(24,505)
|
|
|
(146,090)
|
|
|
(75,280)
|
|
Acquisitions
|
(58,004)
|
|
|
(273,841)
|
|
|
(706,489)
|
|
|
(284,024)
|
|
Acquisition
deposit
|
—
|
|
|
—
|
|
|
46,138
|
|
|
—
|
|
Proceeds from sales
of mineral interests and equipment
|
—
|
|
|
23,631
|
|
|
—
|
|
|
23,631
|
|
Net cash used in investing
activities
|
(137,940)
|
|
|
(274,715)
|
|
|
(806,441)
|
|
|
(335,673)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
—
|
|
|
98,000
|
|
|
—
|
|
|
143,000
|
|
Payments on senior
secured revolving credit facility
|
—
|
|
|
(58,000)
|
|
|
—
|
|
|
(143,000)
|
|
Issuance of 6.125%
senior unsecured notes due 2024
|
200,000
|
|
|
—
|
|
|
200,000
|
|
|
—
|
|
Premium on the
issuance of 6.125% senior unsecured notes due 2024
|
8,250
|
|
|
—
|
|
|
8,250
|
|
|
—
|
|
Issuance of common
stock
|
—
|
|
|
205,858
|
|
|
—
|
|
|
300,807
|
|
Payment of preferred
stock dividends
|
(1,823)
|
|
|
(1,823)
|
|
|
(3,647)
|
|
|
(3,647)
|
|
Payment of deferred
financing costs
|
(6,765)
|
|
|
—
|
|
|
(6,765)
|
|
|
—
|
|
Tax withholdings
related to restricted stock units
|
(974)
|
|
|
(1,918)
|
|
|
(1,053)
|
|
|
(2,038)
|
|
Net cash provided by financing
activities
|
198,688
|
|
|
242,117
|
|
|
196,785
|
|
|
295,122
|
|
Net change in cash
and cash equivalents
|
103,876
|
|
|
(9,304)
|
|
|
(513,844)
|
|
|
(1,017)
|
|
Balance, beginning of
period
|
35,273
|
|
|
9,511
|
|
|
652,993
|
|
|
1,224
|
|
Balance, end of
period
|
$
|
139,149
|
|
|
$
|
207
|
|
|
$
|
139,149
|
|
|
$
|
207
|
|
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
below. 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 its 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 Thursday,
August 3, 2017, to discuss second quarter 2017 financial and
operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Thursday,
August 3, 2017, at 9:00 a.m. Central Time (10:00 a.m. Eastern
Time)
|
Webcast:
|
Live webcast will be
available at www.callon.com in the "Investors" section of the
website
|
Presentation
Slides:
|
Available at
http://ir.callon.com/presentations in the "Investors" section of the
website
|
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:
|
5792667
|
An archive of the conference call webcast will also be available
at www.callon.com in 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
Callon Petroleum Company
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-second-quarter-2017-results-300498678.html
SOURCE Callon Petroleum Company