NATCHEZ, Miss., May 2, 2017 /PRNewswire/ -- Callon Petroleum
Company (NYSE: CPE) ("Callon" or the "Company") today reported
results of operations for the three months ended March 31, 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 first quarter of
2017, and other recent data points include:
- Daily production of 20.4 MBOE/d (78% oil), a sequential
quarterly increase of 11% in total daily production and 14%
increase in daily oil production
- Lease operating expense, including workovers, of $6.61 per BOE, a sequential quarterly decrease of
17%
- Two Wolfcamp A wells in Howard County (WildHorse area) reached
average 30-day peak production rates of 237 BOE/d per 1,000 feet of
completed lateral (91% oil) with a third continuing to build to
peak production rates
- Increase in northern Howard County Wolfcamp A type curve
(7,500' drilled lateral) to 1.3 MMBOE (85% oil)
- Closed the Ameredev transaction in mid-February and
subsequently signed purchase and sale agreements for the
acquisition of an additional 2,626 net acres in Ward County (Spur
area) for $54.3 million, establishing
a position of over 19,300 net surface acres in the Delaware Basin
"We are off to a strong start in 2017 with the increasing impact
of our WildHorse area that is now in program development mode,"
commented Fred Callon, Chairman and
Chief Executive Officer. "Our activity in this core area has
initially focused on northern Howard County where we have
demonstrated the repeatability of exceptional Wolfcamp A results
from larger completion designs. Our efforts in WildHorse will now
move toward the central part of Howard County, focusing on three
development zones, and we will be active with two rigs across our
entire Howard County position throughout 2017. In parallel, we have
been executing our plans to initiate program development in our
recently acquired Delaware Basin
acreage position which will begin with the arrival of our fourth
horizontal drilling rig in July. As we approach this date, we have
been refining our completion designs and landing zone concepts
based on analysis of core data from our Lower Wolfcamp A well that
was placed on production in January
2017 and upgrading the existing infrastructure to support a
two rig development program in the future. We have also been
successful in expanding our footprint in this core area, increasing
our Delaware Basin position by
approximately 15% since we closed our initial acquisition in
February and, importantly, enhancing our opportunity set with the
extension of existing laterals and the addition of additional
locations at attractive valuations."
Operations Update
At March 31, 2017, we had 191
gross (142.4 net) horizontal wells producing from six established
flow units in the Permian Basin. Net daily production for the three
months ended March 31, 2017 grew
approximately 64% to 20.4 MBOE/d ("MBOE/d") (approximately 78% oil)
as compared to the same period of 2016. Sequentially, we grew
production by approximately 11% compared to the fourth quarter of
2016 with a corresponding 14% sequential increase in our oil
volumes.
For the three months ended March 31,
2017, we operated three horizontal drilling rigs, drilling
nine gross (7.8 net) horizontal wells in both the Monarch and
WildHorse areas. We placed a combined nine gross (6.6 net)
horizontal wells on production in the quarter in these two
areas.
WildHorse
During the first quarter, we completed six
wells including three Wolfcamp A wells and three Lower Spraberry
wells. Based on production data from our Wolfcamp A wells in the
Sidewinder field that were completed with larger proppant loadings
(including extended time performance from the Silver City 01AH) and offsetting well results
in the area, we are increasing our Wolfcamp A type curve (7,500'
drilled lateral) in northern Howard County to 1.3 MMBOE (85% oil),
an increase of 85% over the 700 MBOE type curve originally assumed
at the time of the Big Star acquisition in April 2016. In addition, following the recent
completion of our Garrett-Reed 37-48 #8AH well in the Maverick
field and upcoming Wolfcamp A completions in the Fairway field, we
will be re-evaluating our current type curve assumptions in central
Howard County in the coming months.
The following table highlights the three Wolfcamp A wells in
Howard County that achieved peak rates since the beginning of the
year, expressed in absolute barrels of oil equivalent per day
("BOE/d") and production rates per 1,000 feet of completed
lateral:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30-Day
Average
|
|
|
|
|
|
|
|
|
24-Hour Peak
IP
|
|
Peak
IP
|
|
|
|
|
|
|
|
|
(BOE/d;
Two-stream) (a)
|
|
(BOE/d;
Two-stream)
|
24-Hour
|
|
|
|
|
|
|
|
Peak
|
|
|
|
Per
1,000'
|
|
Peak
|
|
|
|
Per
1,000'
|
IP
|
|
|
|
Area
|
|
Completed
|
|
24-Hour
|
|
Production
|
|
Lateral
|
|
30-Day
|
|
Production
|
|
Lateral
|
Date
|
|
Well
|
|
(Field /
Zone)
|
|
Lateral
(ft)
|
|
IP
|
|
(%
oil)
|
|
Feet
|
|
IP
|
|
(%
oil)
|
|
Feet
|
03/16/2017
|
|
Wright-Adams 31-42
#5AH
|
|
WildHorse
(Sidewinder/WCA)
|
|
6,832
|
|
2,333
|
|
90%
|
|
341
|
|
1,976
|
|
91%
|
|
289
|
Pending
|
|
Cheek 28-21
#1AH
|
|
WildHorse
(Sidewinder/WCA)
|
|
9,720
|
|
Flowing
back
|
Flowing
back
|
03/02/2017
|
|
Garrett-Reed 37-48
#8AH
|
|
WildHorse
(Maverick/WCA)
|
|
6,560
|
|
1,530
|
|
92%
|
|
233
|
|
1,211
|
|
90%
|
|
184
|
|
|
(a)
|
24-Hour Peak IPs
correspond to the rates filed with the Railroad Commission of Texas
and are captured using well tests on the specified date, which may
result in an understated rate as the production typically varies
more widely during the early days of production. The 30-Day Average
Peak IP is calculated using well tests on dates taken and allocated
production for all other dates.
|
These wells were completed in individual two-well pads that also
included Lower Spraberry wells. The Lower Spraberry wells employed
larger completion designs than legacy wells in the area and are in
the process of dewatering as they build to peak production
rates.
Monarch
During the first quarter, three Lower
Spraberry wells were placed on production in two flow units within
the zone. In addition, we are in the process of completing a three
well pad including two Lower Spraberry wells and one Wolfcamp A
well that will be our third test of increased density development
in the Lower Spraberry.
Spur
In our newest core operating area, we are in the
final stages of preparation for program development. As part of our
execution plan, we have been upgrading facilities as well as
incorporating the analysis of core data from the Corbets 34-149 02A
into the refinement of our completion designs and target landing
zones from those utilized by the prior operator in two recent wells
that we acquired with our recent transaction. The first of these
wells, the Corbets 34-149 02A, targeted the Lower Wolfcamp A and
has been flowing under natural pressure since being placed on
production in late January. The well has produced in excess of 100
MBOE (90% oil) in the first 90 days since first production and
continues to flow under a pressure management program. The second
well, the Saratoga 34-161 01WB,
was landed in the Wolfcamp B zone and recently placed on
production.
Ward County Acquisitions
Since the closing of our Spur acquisition on February 13, 2017, we have signed agreements to
acquire 2,626 net acres for $54.3
million, equating to an average purchase price of
approximately $20,700 per net surface
acre. In total, these acquisitions will: (i) increase our working
interest in a meaningful portion of our existing gross operated
inventory; (ii) extend the lateral length of 93 gross existing
Wolfcamp A and B locations from a prior blended average of 5,000'
to a new blended average of approximately 9,200'; and (iii) add an
estimated 41 net new Wolfcamp A and B locations (over 90% operated)
with an average lateral length of roughly 7,500'. The combined
acquisition impact of these three factors is the addition of an
estimated equivalent 67 net Wolfcamp locations with an average
lateral length of over 8,000' at a purchase price of approximately
$800 thousand per location. These
acquisitions are expected to be funded with existing cash balances
and credit facility borrowings.
Capital Expenditures
For the three months ended March 31,
2017, we incurred $55.5
million in cash operational capital expenditures compared to
$53.4 million in the fourth quarter
of 2016. Total capital expenditures, inclusive of capitalized
expenses, are detailed below on an accrual and cash basis (in
thousands):
|
|
Three Months Ended
March 31, 2017
|
|
|
Operational
|
|
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
|
Capital
|
|
Other
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
Cash basis
(b)
|
|
$
|
55,503
|
|
$
|
6,230
|
|
$
|
487
|
|
$
|
3,934
|
|
$
|
66,154
|
Timing adjustments
(c)
|
|
|
26,011
|
|
|
—
|
|
|
6,057
|
|
|
—
|
|
|
32,068
|
Non-cash
items
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
572
|
|
|
572
|
Accrual
(GAAP) basis
|
|
$
|
81,514
|
|
$
|
6,230
|
|
$
|
6,544
|
|
$
|
4,506
|
|
$
|
98,794
|
|
|
(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
|
|
|
March 31,
2017
|
|
December 31,
2016
|
|
March 31,
2016
|
Net
production:
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
1,434
|
|
|
1,287
|
|
|
892
|
Natural
gas (MMcf)
|
|
|
2,422
|
|
|
2,413
|
|
|
1,443
|
Total
production (MBOE)
|
|
|
1,838
|
|
|
1,689
|
|
|
1,132
|
Average
daily production (BOE/d)
|
|
|
20,422
|
|
|
18,359
|
|
|
12,440
|
% oil (BOE basis)
|
|
|
78%
|
|
|
76%
|
|
|
79%
|
Oil and natural
gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
Oil
revenue
|
|
$
|
72,008
|
|
$
|
60,559
|
|
$
|
27,443
|
Natural
gas revenue
|
|
|
9,355
|
|
|
8,522
|
|
|
3,255
|
Total
revenue
|
|
$
|
81,363
|
|
$
|
69,081
|
|
$
|
30,698
|
Impact
of cash-settled derivatives
|
|
|
(2,491)
|
|
|
2,079
|
|
|
7,716
|
Adjusted Total Revenue
(i)
|
|
$
|
78,872
|
|
$
|
71,160
|
|
$
|
38,414
|
Total Revenue. For the quarter ended March 31, 2017, Callon reported total revenues of
$81.4 million and total revenues
including cash-settled derivatives ("Adjusted Total Revenue," a
non-GAAP financial measure(i)) of $78.9 million, including the negative
$2.5 million impact of settled
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 20,422 BOE/d compared
to average daily production of 18,359 BOE/d in the fourth quarter
of 2016. Average realized prices, including and excluding the
effects of hedging, are detailed below.
Hedging impacts. For the quarter ended March 31, 2017, Callon recognized the following
hedging-related items (in thousands, except per unit data):
|
|
In
Thousands
|
|
Per
Unit
|
Oil
derivatives
|
|
|
|
|
|
|
Net loss on
settlements
|
|
$
|
(2,524)
|
|
$
|
(1.76)
|
Net gain on fair
value adjustments
|
|
|
17,266
|
|
|
|
Total
gain on oil derivatives
|
|
$
|
14,742
|
|
|
|
Natural gas
derivatives
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
33
|
|
$
|
0.02
|
Net gain on fair
value adjustments
|
|
|
528
|
|
|
|
Total
gain on natural gas derivatives
|
|
$
|
561
|
|
|
|
Total oil &
natural gas derivatives
|
|
|
|
|
|
|
Net loss on
settlements
|
|
$
|
(2,491)
|
|
$
|
(1.36)
|
Net gain on fair
value adjustments
|
|
|
17,794
|
|
|
|
Total
gain on total oil & natural gas derivatives
|
|
$
|
15,303
|
|
|
|
Average realized prices, including and excluding the impact of
cash settled derivatives during the first quarter, were as
follows:
|
|
Three Months
Ended
|
|
|
March 31,
2017
|
Average realized
sales price
|
|
|
|
Oil (per
Bbl) (excluding impact of cash-settled derivatives)
|
|
$
|
50.21
|
Impact of cash-settled
derivatives
|
|
|
(1.76)
|
Oil (per
Bbl) (including impact of cash-settled derivatives)
|
|
$
|
48.45
|
|
|
|
|
Natural
gas (per Mcf) (excluding impact of cash-settled
derivatives)
|
|
$
|
3.86
|
Impact of cash-settled
derivatives
|
|
|
0.02
|
Natural
gas (per Mcf) (including impact of cash-settled
derivatives)
|
|
$
|
3.88
|
|
|
|
|
Total
(per BOE) (excluding impact of cash-settled derivatives)
|
|
$
|
44.27
|
Impact of cash-settled
derivatives
|
|
|
(1.36)
|
Total
(per BOE) (including impact of cash-settled derivatives)
|
|
$
|
42.91
|
|
|
Three Months
Ended
|
|
|
March 31,
2017
|
|
December 31,
2016
|
|
March 31,
2016
|
Additional per BOE
data:
|
|
|
|
|
|
|
|
|
|
Sales
price, excluding impact of cash-settled derivatives
|
|
$
|
44.27
|
|
$
|
40.90
|
|
$
|
27.12
|
Sales
price, including impact of cash-settled derivatives
|
|
|
42.91
|
|
|
42.13
|
|
|
33.93
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense (excluding gathering and treating
expense)
|
|
$
|
6.61
|
|
$
|
7.96
|
|
$
|
5.97
|
Gathering and treating expense
|
|
|
0.43
|
|
|
0.40
|
|
|
0.18
|
Production taxes
|
|
|
3.21
|
|
|
2.20
|
|
|
1.96
|
Depletion, depreciation and amortization
|
|
|
13.29
|
|
|
13.06
|
|
|
13.89
|
Adjusted
G&A (a)
|
|
|
|
|
|
|
|
|
|
Cash component
(b)
|
|
|
2.43
|
|
|
2.84
|
|
|
3.55
|
Non-cash
component
|
|
|
0.57
|
|
|
0.54
|
|
|
0.55
|
|
|
(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.
|
Lease Operating Expenses, including workover and gathering
expense ("LOE"). LOE per BOE for the three months ended
March 31, 2017 was $7.04 per BOE, compared to LOE of $8.36 per BOE in the fourth quarter of 2016. The
decrease in this metric was primarily related to a decrease in the
number of workover activities in the quarter and an increase in
production volumes.
Production Taxes, including ad valorem taxes. Production
taxes were $3.21 per BOE in the first
quarter of 2017, representing approximately 7.3% of total revenue
before the impact of derivative settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
March 31, 2017 was $13.29 per BOE compared to $13.06 per BOE in the fourth quarter of 2016,
attributable to increases in our depreciable asset base and assumed
future development costs related to undeveloped proved reserves
relative to the increase in proved reserves as a result of
additions made through our horizontal drilling efforts and
acquisitions made during the quarter.
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 $5.5
million, or $3.00 per BOE, for
the first quarter of 2017 compared to $5.7
million, or $3.38 per BOE, for
the fourth quarter of 2016. The cash component of Adjusted G&A
was $4.5 million, or $2.43 per BOE, for the first quarter of 2017
compared to $4.8 million, or
$2.84 per BOE, for the fourth quarter
of 2016.
For the first quarter of 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):
|
|
|
For the Three
Months Ended
|
|
|
|
March 31,
2017
|
Total G&A
expense
|
|
|
5,206
|
Less:
Change in the fair value of liability share-based awards
(non-cash)
|
|
$
|
307
|
Adjusted G&A –
total
|
|
|
5,513
|
Restricted stock share-based compensation (non-cash)
|
|
|
(921)
|
Corporate depreciation & amortization (non-cash)
|
|
|
(121)
|
Adjusted G&A –
cash component
|
|
$
|
4,471
|
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 $0.5 million for the three months ended
March 31, 2017. At March 31, 2017 we had a valuation allowance of
$127.1 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 for
the quarter as if the valuation allowance did not exist.
2017 Guidance Update
|
|
Second
Quarter
|
|
Full
Year
|
|
|
2017
Guidance
|
|
2017
Guidance
|
Total production
(BOE/d)
|
|
21,500 -
23,500
|
|
22,500 -
25,500
|
%
oil
|
|
76% - 78%
|
|
75% - 77%
|
Income Statement
Expenses (per BOE)
|
|
|
|
|
LOE,
including workovers
|
|
$6.25 -
$7.00
|
|
$6.00 -
$6.50
|
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
|
|
$0.00 -
$0.00
|
Effective income tax rate
|
|
0%
|
|
0%
|
Capital
expenditures ($MM, accrual basis)
|
|
|
|
|
Drilling
and completion
|
|
$55 - $60
|
|
$240 -
$255
|
Facilities and other (d)
|
|
$35 - $40
|
|
$85 - $95
|
Capitalized expenses (cash component)
|
|
$10 - $12
|
|
$40 - $45
|
Net operated
horizontal well completions
|
|
|
|
|
Midland
Basin
|
|
9 - 11
|
|
30 - 32
|
Delaware
Basin
|
|
1
|
|
3 - 4
|
|
|
(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 first 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 table summarizes our open derivative positions for
the periods indicated:
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Oil
contracts
|
|
2017
|
|
2018
|
Swap contracts
combined with short puts (WTI, enhanced swaps)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
550
|
|
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Swap
|
|
$
|
44.50
|
|
$
|
—
|
Short put
option
|
|
$
|
30.00
|
|
$
|
—
|
Deferred premium
put option
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
250
|
|
|
—
|
Premium
per Bbl
|
|
$
|
2.05
|
|
$
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Long put
option
|
|
$
|
50.00
|
|
$
|
—
|
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
(WTI, two-way collars)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
1,018
|
|
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Ceiling (short
call)
|
|
$
|
58.19
|
|
$
|
—
|
Floor (long
put)
|
|
$
|
47.50
|
|
$
|
—
|
Call option
contracts (short position)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
505
|
|
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Call strike
price
|
|
$
|
50.00
|
|
$
|
—
|
Swap contracts
(Midland basis differential)
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
|
1,650
|
|
|
2,008
|
Weighted
average price per Bbl
|
|
$
|
(0.52)
|
|
$
|
(1.02)
|
Collar contracts
combined with short puts (WTI, three-way collars)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
—
|
|
|
2,738
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
—
|
|
$
|
62.84
|
Floor (long put
option)
|
|
$
|
—
|
|
$
|
50.00
|
Short put
option
|
|
$
|
—
|
|
$
|
40.00
|
|
|
|
|
|
|
|
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Natural gas
contracts
|
|
2017
|
|
2018
|
Collar contracts
combined with short puts (Henry Hub, three-way
collars)
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
1,100
|
|
|
—
|
Weighted
average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
3.71
|
|
$
|
—
|
Floor (long put
option)
|
|
$
|
3.00
|
|
$
|
—
|
Short put
option
|
|
$
|
2.50
|
|
$
|
—
|
Collar contracts
(Henry Hub, two-way collars)
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
1,588
|
|
|
720
|
Weighted
average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
3.72
|
|
$
|
3.84
|
Floor (long put
option)
|
|
$
|
3.10
|
|
$
|
3.40
|
Swap
contracts
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
736
|
|
|
—
|
Weighted
average price per MMBtu
|
|
$
|
3.39
|
|
$
|
—
|
Income (Loss) Available to Common Shareholders. The
Company reported net income available to common shareholders of
$45.3 million in the first quarter of
2017 and Adjusted Income available to common shareholders of
$20.4 million, or $0.10 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
|
|
|
March 31,
2017
|
|
December 31,
2016
|
|
March 31,
2016
|
Income (loss)
available to common stockholders
|
|
$
|
45,305
|
|
$
|
(3,570)
|
|
$
|
(42,933)
|
Change
in valuation allowance
|
|
|
(13,119)
|
|
|
559
|
|
|
14,288
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
22,604
|
Net
(gain) loss on derivatives, net of settlements
|
|
|
(11,566)
|
|
|
7,170
|
|
|
5,621
|
Change
in the fair value of share-based awards
|
|
|
(189)
|
|
|
590
|
|
|
461
|
Withdrawn proxy contest expenses
|
|
|
—
|
|
|
—
|
|
|
144
|
Loss on
early extinguishment of debt
|
|
|
—
|
|
|
8,374
|
|
|
—
|
Adjusted
Income
|
|
$
|
20,431
|
|
$
|
13,123
|
|
$
|
185
|
Adjusted Income per
fully diluted common share
|
|
$
|
0.10
|
|
$
|
0.08
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
March 31,
2017
|
|
December 31,
2016
|
|
March 31,
2016
|
Net income
(loss)
|
|
$
|
47,129
|
|
$
|
(1,746)
|
|
$
|
(41,109)
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
34,776
|
Net
(gain) loss on derivatives, net of settlements
|
|
|
(17,794)
|
|
|
11,030
|
|
|
8,648
|
Non-cash
stock-based compensation expense
|
|
|
639
|
|
|
1,718
|
|
|
1,225
|
Loss on
early extinguishment of debt
|
|
|
—
|
|
|
12,883
|
|
|
—
|
Withdrawn proxy contest expenses
|
|
|
—
|
|
|
—
|
|
|
221
|
Acquisition expense
|
|
|
450
|
|
|
1,263
|
|
|
48
|
Income
tax (benefit) expense
|
|
|
466
|
|
|
48
|
|
|
—
|
Interest
expense
|
|
|
665
|
|
|
1,369
|
|
|
5,491
|
Depreciation, depletion and amortization
|
|
|
24,932
|
|
|
22,512
|
|
|
16,129
|
Accretion expense
|
|
|
184
|
|
|
196
|
|
|
180
|
Adjusted
EBITDA
|
|
$
|
56,671
|
|
$
|
49,273
|
|
$
|
25,609
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the first quarter of 2017 was
$56.2 million and is reconciled to
operating cash flow in the following table (in thousands):
|
|
Three Months
Ended
|
|
|
March 31,
2017
|
|
December 31,
2016
|
|
March 31,
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
47,129
|
|
$
|
(1,746)
|
|
$
|
(41,109)
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
24,932
|
|
|
22,512
|
|
|
16,129
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
34,776
|
Accretion expense
|
|
|
184
|
|
|
196
|
|
|
180
|
Amortization of non-cash debt related items
|
|
|
665
|
|
|
744
|
|
|
781
|
Deferred
income tax expense
|
|
|
466
|
|
|
48
|
|
|
—
|
Net
(gain) loss on derivatives, net of settlements
|
|
|
(17,794)
|
|
|
11,030
|
|
|
8,648
|
Loss on
early extinguishment of debt
|
|
|
—
|
|
|
9,883
|
|
|
—
|
Non-cash
expense related to equity share-based awards
|
|
|
930
|
|
|
811
|
|
|
516
|
Change
in the fair value of liability share-based awards
|
|
|
(291)
|
|
|
908
|
|
|
709
|
Discretionary cash
flow
|
|
$
|
56,221
|
|
$
|
44,386
|
|
$
|
20,630
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital
|
|
|
5,890
|
|
|
(7,832)
|
|
|
5,582
|
Payments
to settle asset retirement obligations
|
|
|
(765)
|
|
|
(576)
|
|
|
(161)
|
Payments
to settle vested liability share-based awards
|
|
|
(8,662)
|
|
|
—
|
|
|
(9,807)
|
Net cash provided by
operating activities
|
|
$
|
52,684
|
|
$
|
35,978
|
|
$
|
16,244
|
Callon Petroleum
Company
|
Consolidated
Balance Sheets
|
(in thousands,
except par and per share values and share data)
|
|
|
March 31,
2017
|
|
December 31,
2016
|
ASSETS
|
|
Unaudited
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
35,273
|
|
$
|
652,993
|
Accounts
receivable
|
|
75,959
|
|
|
69,783
|
Fair value of
derivatives
|
|
3,093
|
|
|
103
|
Other current
assets
|
|
1,671
|
|
|
2,247
|
Total current
assets
|
|
115,996
|
|
|
725,126
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
|
|
Evaluated properties
|
|
3,009,059
|
|
|
2,754,353
|
Less
accumulated depreciation, depletion, amortization and
impairment
|
|
(1,972,091)
|
|
|
(1,947,673)
|
Net
evaluated oil and natural gas properties
|
|
1,036,968
|
|
|
806,680
|
Unevaluated properties
|
|
1,154,850
|
|
|
668,721
|
Total oil and natural
gas properties
|
|
2,191,818
|
|
|
1,475,401
|
Other property and
equipment, net
|
|
18,067
|
|
|
14,114
|
Restricted
investments
|
|
3,339
|
|
|
3,332
|
Deferred financing
costs related to the senior secured revolving credit
facility
|
|
2,744
|
|
|
3,092
|
Fair value of
derivatives
|
|
2,939
|
|
|
—
|
Acquisition
deposit
|
|
—
|
|
|
46,138
|
Other assets,
net
|
|
676
|
|
|
384
|
Total
assets
|
$
|
2,335,579
|
|
$
|
2,267,587
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
131,252
|
|
$
|
95,577
|
Accrued
interest
|
|
12,114
|
|
|
6,057
|
Cash-settleable
restricted stock unit awards
|
|
4,025
|
|
|
8,919
|
Asset retirement
obligations
|
|
1,588
|
|
|
2,729
|
Fair value of
derivatives
|
|
6,430
|
|
|
18,268
|
Total current
liabilities
|
|
155,409
|
|
|
131,550
|
Senior secured
revolving credit facility
|
|
—
|
|
|
—
|
6.125% senior
unsecured notes due 2024, net of unamortized deferred financing
costs
|
|
390,536
|
|
|
390,219
|
Asset retirement
obligations
|
|
4,652
|
|
|
3,932
|
Cash-settleable
restricted stock unit awards
|
|
4,108
|
|
|
8,071
|
Deferred tax
liability
|
|
556
|
|
|
90
|
Fair value of
derivatives
|
|
—
|
|
|
28
|
Other long-term
liabilities
|
|
285
|
|
|
295
|
Total
liabilities
|
|
555,546
|
|
|
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;
201,054,884 and 201,041,320 shares outstanding,
respectively
|
|
2,011
|
|
|
2,010
|
Capital in excess of
par value
|
|
2,173,243
|
|
|
2,171,514
|
Accumulated
deficit
|
|
(395,236)
|
|
|
(440,137)
|
Total stockholders'
equity
|
|
1,780,033
|
|
|
1,733,402
|
Total liabilities and
stockholders' equity
|
$
|
2,335,579
|
|
$
|
2,267,587
|
Callon Petroleum
Company
|
Consolidated
Statements of Operations
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
Three Months Ended
March 31,
|
|
|
|
2017
|
|
|
2016
|
Operating
revenues:
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
72,008
|
|
$
|
27,443
|
Natural
gas sales
|
|
|
9,355
|
|
|
3,255
|
Total operating
revenues
|
|
|
81,363
|
|
|
30,698
|
Operating
expenses:
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
12,937
|
|
|
6,957
|
Production taxes
|
|
|
5,904
|
|
|
2,220
|
Depreciation, depletion and amortization
|
|
|
24,433
|
|
|
15,722
|
General
and administrative
|
|
|
5,206
|
|
|
5,562
|
Accretion expense
|
|
|
184
|
|
|
180
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
34,776
|
Acquisition expense
|
|
|
450
|
|
|
48
|
Total operating
expenses
|
|
|
49,114
|
|
|
65,465
|
Income
(loss) from operations
|
|
|
32,249
|
|
|
(34,767)
|
Other (income)
expenses:
|
|
|
|
|
|
|
Interest
expense, net of capitalized amounts
|
|
|
665
|
|
|
5,491
|
(Gain)
loss on derivative contracts
|
|
|
(15,303)
|
|
|
932
|
Other
income
|
|
|
(708)
|
|
|
(81)
|
Total other (income)
expense
|
|
|
(15,346)
|
|
|
6,342
|
Income
(loss) before income taxes
|
|
|
47,595
|
|
|
(41,109)
|
Income tax
expense
|
|
|
466
|
|
|
—
|
Net income
(loss)
|
|
|
47,129
|
|
|
(41,109)
|
Preferred stock
dividends
|
|
|
(1,824)
|
|
|
(1,824)
|
Income (loss)
available to common stockholders
|
|
$
|
45,305
|
|
$
|
(42,933)
|
Income (loss)
per common share:
|
|
|
|
|
|
|
Basic
|
|
$
|
0.23
|
|
$
|
(0.51)
|
Diluted
|
|
$
|
0.22
|
|
$
|
(0.51)
|
Shares
used in computing income (loss) per common share:
|
|
|
|
|
|
|
Basic
|
|
|
201,054
|
|
|
83,582
|
Diluted
|
|
|
201,740
|
|
|
83,582
|
Callon Petroleum
Company
|
Consolidated
Statements of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
Three Months Ended
March 31,
|
|
|
2017
|
|
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
47,129
|
|
$
|
(41,109)
|
Adjustments to
reconcile net income to cash provided by operating
activities:
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
24,932
|
|
|
16,129
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
34,776
|
Accretion expense
|
|
|
184
|
|
|
180
|
Amortization of non-cash debt related items
|
|
|
665
|
|
|
781
|
Deferred
income tax expense
|
|
|
466
|
|
|
—
|
Net
(gain) loss on derivatives, net of settlements
|
|
|
(17,794)
|
|
|
8,648
|
Non-cash
expense related to equity share-based awards
|
|
|
930
|
|
|
516
|
Change
in the fair value of liability share-based awards
|
|
|
(291)
|
|
|
709
|
Payments
to settle asset retirement obligations
|
|
|
(765)
|
|
|
(161)
|
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(4,066)
|
|
|
5,941
|
Other current
assets
|
|
|
576
|
|
|
580
|
Current
liabilities
|
|
|
9,903
|
|
|
(717)
|
Change in other
long-term liabilities
|
|
|
—
|
|
|
11
|
Change in other
assets, net
|
|
|
(523)
|
|
|
(233)
|
Payments
to settle vested liability share-based awards
|
|
|
(8,662)
|
|
|
(9,807)
|
Net cash provided
by operating activities
|
|
|
52,684
|
|
|
16,244
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(66,154)
|
|
|
(50,775)
|
Acquisitions
|
|
|
(648,485)
|
|
|
(10,183)
|
Acquisition
deposit
|
|
|
46,138
|
|
|
—
|
Net cash used in
investing activities
|
|
|
(668,501)
|
|
|
(60,958)
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
|
|
—
|
|
|
45,000
|
Payments on senior
secured revolving credit facility
|
|
|
—
|
|
|
(85,000)
|
Issuance of common
stock
|
|
|
—
|
|
|
94,949
|
Payment of preferred
stock dividends
|
|
|
(1,824)
|
|
|
(1,824)
|
Tax withholdings
related to restricted stock units
|
|
|
(79)
|
|
|
(124)
|
Net cash provided
by (used in) financing activities
|
|
|
(1,903)
|
|
|
53,001
|
Net change in cash
and cash equivalents
|
|
|
(617,720)
|
|
|
8,287
|
Balance,
beginning of period
|
|
|
652,993
|
|
|
1,224
|
Balance,
end of period
|
|
$
|
35,273
|
|
$
|
9,511
|
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
(Loss)," "Adjusted EBITDA," and "Adjusted Total Revenues." 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 and discretionary cash
flow per diluted share are 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 Revenues
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 Wednesday, May 3, 2017, to discuss first quarter
2017 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Wednesday, May 3,
2017, at 8:00 a.m. Central Time (9:00 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:
|
5057175
|
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:
Eric Williams
Manager, Investor Relations
1-800-451-1294
|
|
|
|
|
|
|
|
|
|
|
i.
|
See "Non-GAAP
Financial Measures and Reconciliations" included within this
release for related disclosures and calculations
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-first-quarter-2017-results-300449969.html
SOURCE Callon Petroleum Company