NATCHEZ, Miss., Aug. 8, 2016 /PRNewswire/ -- Callon
Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today
reported results of operations for the three months ended
June 30, 2016.
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
2016 and other recent data points include:
- Net daily production of 13,451 barrels of oil equivalent per
day ("BOE/d"), an increase of 8% compared to the first quarter of
2016, comprised of 77% oil volume
- Estimated July 2016 net daily
production of over 16,000 BOE/d after a prolonged period of
production downtime in June 2016
caused by offsetting completions activity at the Carpe Diem field,
compounded by the impact of electrical outages
- Lease operating expense, including workovers, of $5.97 per barrel of oil equivalent ("BOE"), a
decrease of 3% from the first quarter of 2016
- GAAP loss per diluted common share of $0.61 and Adjusted Income per fully diluted
common share, a non-GAAP financial measure(i), of
$0.05
- Closed two Midland Basin
transactions for a total purchase price of $362.6 million, including the establishment of a
new core operating area in Howard
County
- Completed first Callon-operated Wolfcamp A well (completed
lateral length of 7,363') in northern Howard County which has produced approximately
48,600 BOE (90% oil) in the first 30 days after being placed on
production in early July 2016
- Borrowing base increased 28% from $300
million to $385 million
following the closing of recent transactions
- Recently added second horizontal rig to be focused in the
WildHorse area in Howard
County
- Signed purchase and sale agreement for the acquisition of an
incremental 4% working interest in the Casselman and Bohannon
fields (the "CaBo area")
"It was an important quarter for our organization, demonstrating
our ability to manage through periods of commodity price weakness
by living within our cash flow while delivering capital efficient
production growth. This solid operating and financial position also
allowed us to complete two acquisitions that almost doubled our
surface acreage in the Midland
Basin, expanding our inventory of investments that we expect will
deliver solid returns on capital through all phases of commodity
cycles." commented Fred Callon,
Chairman and Chief Executive Officer. "With a strong balance sheet
and low cost operating structure, we have returned our second
horizontal rig to service in August
2016 and are planning to add a third horizontal rig in early
2017 with continued signs of rebalancing in the oil markets. A
large portion of this increased drilling activity will be focused
in Howard County, a rapidly
emerging core area which has produced encouraging well results from
three delineated zones to date, including our recent Wolfcamp A
well."
Operations Update
At June 30, 2016, Callon had 118
gross (93.0 net) horizontal wells producing from five established
zones. Our net daily production for the three months ended
June 30, 2016, grew approximately 41%
to 13,451 BOE/d (approximately 77% oil) as compared to the same
period of 2015. Sequentially, we grew production more than 8%
compared to the first quarter of 2016.
For the three months ended June 30,
2016, we drilled 6 gross (3.7 net) horizontal wells,
completed 5 gross (3.4 net) horizontal wells, and placed 5 gross
(3.4 net) horizontal wells on production. As of June 30, 2016, we had 6 gross (4.2 net)
horizontal wells awaiting completion, including 2 gross drilled,
uncompleted wells recently acquired as part of our western
Reagan County transaction.
Monarch
Production from the Monarch areas was adversely impacted during
most of the month of June 2016 by
production disruptions at our largest producing field, Carpe Diem.
Several wells in the field experienced hydraulic interference from
two offsetting completions being performed by other operators
offsetting the eastern side of Carpe Diem. The situation was
compounded by power outages caused by adverse weather conditions
which hindered our efforts to de-water the wells in order to
restore normalized production levels. We estimate that this
unexpected downtime negatively impacted total net production
volumes in the quarter by approximately 425 BOE/d.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
Months Ended June 30, 2016
|
|
|
Drilled
|
|
Completed
|
|
Placed on
Production
|
|
Awaiting
Completion
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Monarch
|
|
6
|
|
3.7
|
|
4
|
|
2.4
|
|
5
|
|
3.4
|
|
4
|
|
3.1
|
During the second quarter, we continued our focus on development
of the Lower Spraberry on our Monarch assets in Midland County. For the three months ended
June 30th, we drilled 6
gross (3.7 net) wells, completed 4 gross (2.4 net) wells and placed
5 gross (3.4 net) wells on production. Since placing our first two
Lower Spraberry wells on production in November 2014, we now have 28 gross wells
producing from two levels of this zone across our asset base,
including 25 at Monarch, with drilled lateral lengths ranging from
5,000' to 10,000'.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
Completed
|
|
24-Hour
|
|
Production
|
|
Lateral
|
|
30-Day
|
|
Production
|
|
Lateral
|
Date
|
|
Well
|
|
County
|
|
Lateral
(ft)
|
|
IP
|
|
(%
oil)
|
|
Feet
|
|
IP
|
|
(%
oil)
|
|
Feet
|
06/21/2016
|
|
Pecan Acres 22A2
09SH
|
|
Midland
|
|
4,652'
|
|
729
|
|
87%
|
|
157
|
|
745
|
|
85%
|
|
160
|
06/21/2016
|
|
Pecan Acres 22A3
10SH
|
|
Midland
|
|
4,432'
|
|
719
|
|
87%
|
|
162
|
|
741
|
|
87%
|
|
167
|
06/02/2016
|
|
Casselman 8
18SH
|
|
Midland
|
|
4,675'
|
|
839
|
|
85%
|
|
180
|
|
674
|
|
84%
|
|
144
|
05/29/2016
|
|
Casselman 8
16SH
|
|
Midland
|
|
4,671'
|
|
867
|
|
79%
|
|
186
|
|
638
|
|
86%
|
|
137
|
05/25/2016
|
|
Kendra-Annie 10
21SH
|
|
Midland
|
|
8,178'
|
|
935
|
|
89%
|
|
114
|
|
697
|
|
89%
|
|
85
|
05/04/2016
|
|
Casselman 8
17SH
|
|
Midland
|
|
4,903'
|
|
923
|
|
83%
|
|
188
|
|
668
|
|
87%
|
|
136
|
04/17/2016
|
|
Kendra-Amanda
29SH
|
|
Midland
|
|
8,432'
|
|
1,242
|
|
89%
|
|
147
|
|
926
|
|
89%
|
|
110
|
04/01/2016
|
|
Casselman 10
09SH
|
|
Midland
|
|
4,182'
|
|
674
|
|
90%
|
|
161
|
|
562
|
|
87%
|
|
134
|
|
|
(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 allocated production, and is
occasionally greater than the reported 24-Hour Peak IP if the well
test on that date captured a lower rate than the average for the
period.
|
We continue to deliver strong, consistent well results and
capital efficiency from our Monarch development program. As
detailed in the table above, eight Lower Spraberry wells, all in
the lower bench of the zone (or, "LLS"), achieved 24-hour peak
initial production ("IP") rates during the quarter. The LLS wells
averaged a 24-hour peak IP of 866 Boe/d (or 162 Boepd per 1,000')
and a 30-day average peak IP of 706 Boe/d (or 134 Boepd per
1,000').
At our Pecan Acres field, we placed 3 gross (1.4 net) LLS wells
on production. While one of the wells continues to build towards
its 30-day average peak IP, the other two wells yielded an average
30-day average peak IP of 743 BOE/d (86% oil) or 164 BOE/d per
1,000' from an average drilled lateral length of approximately
5,000'. We also plan to commence completion operations on our first
Wolfcamp A well in the Monarch area in August 2016 which is being developed as a stacked
lateral with a LLS well. Each of the wells was drilled to a lateral
length of approximately 10,000'.
We are currently completing a three-well pad with an average
drilled lateral length of approximately 9,750' in our Carpe Diem
field with two of the wells targeting the upper section of the
Lower Spraberry ("ULS") and the third well targeting the LLS. This
pad was drilled on 11 wells-per-section spacing, supported by
long-term production and pressure data from our previous well
density tests. In addition, we plan to drill an additional two LLS
wells at Carpe Diem in the third quarter with planned drilled
lateral lengths of 10,000' that were increased from a previous
planned lateral length of 5,000' after a recently completed
partnership agreement with an offset operator.
We continue to build upon our well density tests of the Lower
Spraberry in the Monarch area which have been focused on the Carpe
Diem field to date. The next step in our progression of this
initiative will be a 13 wells-per-section test in the CaBo area
that was spud in July 2016, with two
wells landed in the LLS and the third landed in the ULS.
Callon recently signed a purchase agreement for the acquisition
of an incremental 4% working interest in the CaBo area, increasing
our working interest in the area to approximately 75%. The purchase
price for the acquired interest is $13
million with an effective date of August 1, 2016. Completion of the acquisition is
subject to customary closing conditions.
WildHorse
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
Months Ended June 30, 2016
|
|
|
Drilled
|
|
Completed
|
|
Placed on
Production
|
|
Awaiting
Completion
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
WildHorse
|
|
—
|
|
—
|
|
1
|
|
1.0
|
|
—
|
|
—
|
|
—
|
|
—
|
During the second quarter, we began our first operated
completion in the recently acquired WildHorse area in Howard County, Texas. The well (Silver City
Unit A #1H; 100% WI) was completed in the Wolfcamp A with a lateral
length of 7,363'. It is the northernmost Wolfcamp A completion to
date on our operated acreage, located in our Sidewinder field in
northwest Howard County. After a
first oil production date on July 3,
2016, the well has produced approximately 48,600 BOE (90%
oil) during the first 30 days of production.
We anticipate initiating our operated drilling program in
Howard County during the fourth
quarter of 2016 with a dedicated one-rig program. The rig will
initially drill two-well pads in the Wolfcamp A at our Fairway
acreage in central Howard County,
before expanding its scope to include our broader footprint and
other prospective zones in 2017, including the Lower Spraberry and
Wolfcamp B. We currently expect to place our first two-well pad
from this program on production in mid-December 2016. Additionally, we are preparing
to further increase our drilling activity in the WildHorse area
should commodity prices warrant the addition of a third rig to our
operated drilling program.
Ranger
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30-Day
Average
|
|
|
|
|
|
|
24-Hour Peak
IP
|
|
Peak
IP
|
|
|
|
|
|
|
(BOE/d;
Two-stream)
|
|
(BOE/d;
Two-stream)
|
|
|
|
|
|
|
Peak
|
|
|
|
Per
1,000'
|
|
Peak
|
|
|
|
Per
1,000'
|
|
|
|
|
Completed
|
|
24-Hour
|
|
Production
|
|
Lateral
|
|
30-Day
|
|
Production
|
|
Lateral
|
Well
|
|
County
|
|
Lateral
(ft)
|
|
IP
|
|
(%
oil)
|
|
Feet
|
|
IP
|
|
(%
oil)
|
|
Feet
|
Turner AR Unit B
08HK
|
|
Reagan
|
|
7,518'
|
|
1,716
|
|
86%
|
|
228
|
|
1,279
|
|
0%
|
|
170
|
Turner AR Unit C
13HK
|
|
Reagan
|
|
7,430'
|
|
1,758
|
|
86%
|
|
237
|
|
1,253
|
|
0%
|
|
169
|
The two wells listed in the table above were completed using a
new generation completion design employed by the previous operator
of our newly acquired Lonesome Draw field, which included shorter
stage lengths and higher proppant volumes. We will continue to
evaluate the longer-term performance of wells completed with this
enhanced design, but early indications include 30-day average peak
IPs trending approximately 50% higher versus older generation
completions we used in the Ranger area. We plan to incorporate
these enhanced completion techniques in two upcoming completions of
drilled, uncompleted wells acquired at Lonesome Draw. These wells
will be targeting the Wolfcamp A and Upper Wolfcamp B zones and are
planned to commence completion operations in August 2016.
Capital expenditures
For the three months ended June 30,
2016, we accrued $21.3 million
in operational capital expenditures, including facilities
expenditures of $4.0 million,
compared to $35.0 million in the
first quarter of 2016. Total capital expenditures, inclusive of
capitalized expenses, are detailed below on an accrual and cash
basis (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, 2016
|
|
|
Operational
Capital
Expenditures
|
|
Capitalized
Interest
|
|
Capitalized
G&A
|
|
Total Capital
Expenditures
|
Cash basis
(a)
|
|
$
|
17,965
|
|
$
|
3,687
|
|
$
|
2,853
|
|
$
|
24,505
|
Timing adjustments
(b)
|
|
|
3,309
|
|
|
(150)
|
|
|
—
|
|
|
3,159
|
Non-cash
items
|
|
|
—
|
|
|
—
|
|
|
1,854
|
|
|
1,854
|
Accrual
(GAAP) basis
|
|
$
|
21,274
|
|
$
|
3,537
|
|
$
|
4,707
|
|
$
|
29,518
|
|
|
(a)
|
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.
|
(b)
|
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,
2016
|
|
March 31,
2016
|
|
June 30,
2015
|
Net
production:
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
948
|
|
|
892
|
|
|
685
|
Natural
gas (MMcf)
|
|
|
1,658
|
|
|
1,443
|
|
|
1,084
|
Total
production (MBOE)
|
|
|
1,224
|
|
|
1,132
|
|
|
866
|
Average
daily production (BOE/d)
|
|
|
13,451
|
|
|
12,440
|
|
|
9,516
|
% oil
(BOE basis)
|
|
|
77%
|
|
|
79%
|
|
|
79%
|
Oil and natural
gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
Oil
revenue
|
|
$
|
40,555
|
|
$
|
27,443
|
|
$
|
36,093
|
Natural
gas revenue
|
|
|
4,590
|
|
|
3,255
|
|
|
3,149
|
Total
revenue
|
|
$
|
45,145
|
|
$
|
30,698
|
|
$
|
39,242
|
Impact
of cash-settled derivatives
|
|
|
4,017
|
|
|
7,716
|
|
|
4,965
|
Adjusted Total Revenue
(i)
|
|
$
|
49,162
|
|
$
|
38,414
|
|
$
|
44,207
|
Total Revenue. For the quarter ended June 30, 2016, Callon reported total revenues of
$45.2 million and total revenues
including cash-settled derivatives ("Adjusted Total Revenue," a
non-GAAP financial measure(i)) of $49.2 million, including the $4.0 million impact of settled derivative
contracts. The table above reconciles to the related GAAP measure
of the Company's revenue to Adjusted Total Revenue. Average daily
production for the quarter was 13,451 BOE/d compared to average
daily production of 12,440 BOE/d in the first quarter of 2016.
Average realized prices, including and excluding the effects of
hedging, are detailed below.
Hedging impacts. For the quarter ended June 30, 2016, Callon recognized the following
hedging-related items:
|
|
|
|
|
|
|
|
|
In
Thousands
|
|
Per
Unit
|
Oil derivatives
contracts
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
3,707
|
|
$
|
3.91
|
Net loss on fair
value adjustments
|
|
|
(18,466)
|
|
|
|
Total
net loss on oil derivatives contracts
|
|
$
|
(14,759)
|
|
|
|
|
|
|
|
|
|
|
Natural gas
derivatives contracts
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
310
|
|
$
|
0.19
|
Net gain on fair
value adjustments
|
|
|
(1,035)
|
|
|
|
Total
net gain on natural gas derivatives contracts
|
|
$
|
(725)
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
contracts
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
4,017
|
|
$
|
3.29
|
Net loss on fair
value adjustments
|
|
|
(19,501)
|
|
|
|
Total
net loss on total derivatives contracts
|
|
$
|
(15,484)
|
|
|
|
Average realized prices, including and excluding the impact of
cash settled derivatives during the second quarter, were as
follows:
|
|
|
|
|
|
Three Months
Ended
|
|
|
June 30,
2016
|
Average realized
sales price
|
|
|
|
Oil (per
Bbl) (excluding impact of cash-settled derivatives)
|
|
$
|
42.78
|
Impact of cash-settled
derivatives
|
|
|
3.91
|
Oil (per
Bbl) (including impact of cash-settled derivatives)
|
|
$
|
46.69
|
|
|
|
|
Natural
gas (per Mcf) (excluding impact of cash-settled
derivatives)
|
|
$
|
2.77
|
Impact of cash-settled
derivatives
|
|
|
0.19
|
Natural
gas (per Mcf) (including impact of cash-settled
derivatives)
|
|
$
|
2.96
|
|
|
|
|
Total
(per BOE) (excluding impact of cash-settled derivatives)
|
|
$
|
36.88
|
Impact of cash-settled
derivatives
|
|
|
3.29
|
Total
(per BOE) (including impact of cash-settled derivatives)
|
|
$
|
40.17
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
June 30,
2016
|
|
March 31,
2016
|
|
June 30,
2015
|
Additional per BOE
data:
|
|
|
|
|
|
|
|
|
|
Sales
price, excluding impact of cash-settled derivatives
|
|
$
|
36.88
|
|
$
|
27.12
|
|
$
|
45.31
|
Sales
price, including impact of cash-settled derivatives
|
|
|
40.17
|
|
|
33.93
|
|
|
51.05
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
$
|
5.97
|
|
$
|
6.15
|
|
$
|
7.59
|
Production taxes
|
|
|
2.01
|
|
|
1.96
|
|
|
3.41
|
Depletion, depreciation and amortization
|
|
|
13.31
|
|
|
13.89
|
|
|
20.31
|
G&A
|
|
|
5.15
|
|
|
4.91
|
|
|
6.65
|
Adjusted
G&A - total (a)
|
|
|
3.55
|
|
|
4.10
|
|
|
4.53
|
Adjusted
G&A - cash component (b)
|
|
|
2.92
|
|
|
3.55
|
|
|
3.85
|
|
|
(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 expense
("LOE"). LOE per BOE for the three months ended
June 30, 2016 was $5.97 per BOE, compared to LOE of $6.15 per BOE in the first quarter of 2016.
Production Taxes, including ad valorem taxes. Production
taxes were $2.01 per BOE in the
second quarter of 2016, representing approximately 5.4% of total
revenue before the impact of derivative settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
June 30, 2016 was $13.31 per BOE compared to $13.89 per BOE in the first quarter of 2016, with
the decrease in per unit DD&A being attributable to increases
in proved reserves relative to our depreciable asset base and
assumed future development costs related to undeveloped proved
reserves. The decrease in our depreciable base was primarily
related to the write-down of oil and natural gas properties during
2015 and the first half of 2016.
General and Administrative ("G&A"). G&A for
the second quarter of 2015 was $6.3
million, or $5.15 per BOE,
compared to $5.6 million, or
$4.91 per BOE, for the first quarter
of 2016. G&A, excluding certain non-cash incentive share-based
compensation valuation adjustments, ("Adjusted G&A", a non-GAAP
measure(i)) was $4.3
million, or $3.55 per BOE, for
the second quarter of 2016 compared to $4.6
million, or $4.10 per BOE, for
the first quarter of 2016. The cash component of Adjusted G&A
was $3.6 million, or $2.92 per BOE, for the second quarter of 2016
compared to $4.0 million, or
$3.55 per BOE, for the first quarter
of 2016.
For the second quarter of 2016, 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):
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
Non-Cash
|
|
Total
|
G&A
expenses
|
|
|
|
|
|
|
|
|
|
Cash
G&A
|
|
$
|
3,578
|
|
$
|
—
|
|
$
|
3,578
|
Restricted stock share-based compensation
|
|
|
—
|
|
|
655
|
|
|
655
|
Change
in the fair value of liability share-based awards
|
|
|
—
|
|
|
1,954
|
|
|
1,954
|
Corporate depreciation & amortization
|
|
|
—
|
|
|
115
|
|
|
115
|
Total G&A
expense:
|
|
$
|
3,578
|
|
$
|
2,724
|
|
$
|
6,302
|
Adjusted
G&A (i)
|
|
|
|
|
|
|
|
|
|
Less:
Change in the fair value of liability share-based awards
|
|
|
|
|
|
|
|
$
|
(1,954)
|
Adjusted G&A –
total
|
|
|
|
|
|
|
|
|
4,348
|
Restricted stock share-based compensation
|
|
|
|
|
|
|
|
|
(655)
|
Corporate depreciation & amortization
|
|
|
|
|
|
|
|
|
(115)
|
Adjusted G&A –
cash component
|
|
|
|
|
|
|
|
$
|
3,578
|
Write-down of Oil and Natural Gas Properties. As a result
of the ceiling test limitation, the Company recognized a write-down
of oil and natural gas properties of $61.0
million in the second quarter of 2016.
Income (Loss) Available to Common Shareholders. The
Company reported a net loss available to common shareholders of
$71.9 million in the second quarter
of 2016 and Adjusted Income available to common shareholders of
$6.1 million, or $0.05 per diluted share.
Capital Budget Update
Following the closing of its recent Midland Basin acquisitions, the Company has
completed a review of its operational plans for the balance of
2016. Callon recently returned a second horizontal rig to service
after being idled in the first quarter of 2016. The rig will
initially be focused on program development of the Wolfcamp A zone
in the WildHorse area after drilling two 10,000' lateral wells
targeting the LLS at the Carpe Diem field. In addition, the Company
has budgeted for investments in facilities, seismic and land to
support the longer-term development plans in each of our focus
areas, including the potential addition of a third horizontal rig
during the first half of 2017.
A breakdown of the Company's anticipated 2016 operational plan
and associated expenditures is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
1st Half
2016
|
|
2nd Half
2016
|
|
Total
|
Operational
activity (gross / net)
|
|
|
|
|
|
|
|
|
|
Drill
wells
|
|
|
11 / 8.0
|
|
|
15 / 10.2
|
|
|
26 / 18.2
|
Completed wells
|
|
|
14 / 10.5
|
|
|
15 / 10.3
|
|
|
29 / 20.8
|
Wells
placed on production
|
|
|
13 / 9.5
|
|
|
13 / 8.9
|
|
|
26 / 18.4
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures (in millions, accrual basis)
|
|
|
|
|
|
|
|
|
|
Drilling
and completion
|
|
$
|
46.2
|
|
$
|
58.4
|
|
$
|
104.6
|
Facilities
|
|
|
9.2
|
|
|
16.2
|
|
|
25.4
|
Operational capital
expenditures
|
|
|
55.4
|
|
|
74.6
|
|
|
130.0
|
Seismic
|
|
|
0.8
|
|
|
2.5
|
|
|
3.3
|
Land and
other
|
|
|
—
|
|
|
6.7
|
|
|
6.7
|
Total capital
expenditures (excl. capitalized expenses)
|
|
$
|
56.2
|
|
$
|
83.8
|
|
$
|
140.0
|
2016 Guidance Update
|
|
|
|
|
|
|
|
|
Third
Quarter
|
|
Updated Full
Year
|
|
Full Year
(a)
|
|
|
2016
Guidance
|
|
2016
Guidance
|
|
Guidance
Change
|
Total production
(BOE/d)
|
|
16,000 -
17,000
|
|
14,500 -
15,500
|
|
500
|
%
oil
|
|
75% - 77%
|
|
76% - 80%
|
|
(1%)
|
% oil
hedged (b)
|
|
49%
|
|
48%
|
|
|
Average
swap/long-put price (b)
|
|
$48.84
|
|
$50.04
|
|
|
Expenses (per
BOE)
|
|
|
|
|
|
|
LOE,
including workovers
|
|
$5.75 -
$6.25
|
|
$5.75 -
$6.25
|
|
$(1.00)
|
Production taxes, including ad valorem (% unhedged
revenue)
|
|
7%
|
|
7%
|
|
—
|
Adjusted
G&A (c)
|
|
$3.25 -
$3.75
|
|
$3.25 -
$3.75
|
|
$(0.05)
|
Adjusted
G&A - cash component (d)
|
|
$2.50 -
$3.00
|
|
$2.35 -
$2.85
|
|
$(0.55)
|
Total capital
expenditures
|
|
|
|
|
|
|
Accrual
basis ($MM)
|
|
$34 - $38
|
|
$140
|
|
$40
|
|
|
(a)
|
Based on the midpoint
of guidance.
|
(b)
|
Volumes presented in
the Updated Full Year 2016 Guidance column include volumes hedged
and the average swap/long put price for the remainder of the year
only.
|
(c)
|
Excludes certain
non-recurring expenses and non-cash valuation adjustments. The
reconciliation above provides a reconciliation of second quarter
2016 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.
|
(d)
|
Excludes stock-based
compensation and corporate depreciation and amortization. See the
Non-GAAP related disclosures referenced in the footnote (c)
above.
|
Hedge Portfolio Summary
The following table summarizes our open derivative positions as
of August 8, 2016:
|
|
|
|
|
|
|
|
|
For the Remainder
of
|
|
For the Full Year
of
|
Oil
contracts
|
|
2016
|
|
2017
|
Swap contracts
(WTI)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
460
|
|
|
—
|
Weighted
average price per Bbl
|
|
$
|
58.10
|
|
$
|
—
|
Swap contracts
combined with short puts (WTI, enhanced swaps)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
|
|
|
730
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Swap
|
|
$
|
—
|
|
$
|
44.50
|
Short put
option
|
|
$
|
—
|
|
$
|
30.00
|
Collar contracts
combined with short puts (WTI, three-way collars)
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
|
276
|
|
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
63.33
|
|
$
|
—
|
Floor (long put
option)
|
|
$
|
53.33
|
|
$
|
—
|
Short put
option
|
|
$
|
38.77
|
|
$
|
—
|
Collar contracts
(WTI, two-way collars)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
368
|
|
|
438
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Ceiling (short
call)
|
|
$
|
46.50
|
|
$
|
59.05
|
Floor (long
put)
|
|
$
|
37.50
|
|
$
|
47.50
|
Call option
contracts (short position)
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
—
|
|
|
670
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Call strike
price
|
|
$
|
—
|
|
$
|
50.00
|
Swap contracts
(Midland basis differentials)
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
|
736
|
|
|
—
|
Weighted
average price per Bbl
|
|
$
|
0.17
|
|
$
|
—
|
|
|
|
|
|
|
|
Natural gas
contracts
|
|
|
|
|
|
|
Swap contracts
(Henry Hub)
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
1,104
|
|
|
—
|
Weighted
average price per MMBtu
|
|
$
|
2.52
|
|
$
|
—
|
Collar contracts
combined with short puts (three-way collars)
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
|
|
|
1,460
|
Weighted
average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
—
|
|
$
|
3.71
|
Floor (long put
option)
|
|
$
|
—
|
|
$
|
3.00
|
Short put
option
|
|
$
|
—
|
|
$
|
2.50
|
The following tables reconcile to the related GAAP measure the
Company's loss available to common stockholders to Adjusted Income
and the Company's net loss to Adjusted EBITDA (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
June 30,
2016
|
|
March 31,
2016
|
|
June 30,
2015
|
Loss available to
common stockholders
|
|
$
|
(71,920)
|
|
$
|
(42,933)
|
|
$
|
(6,940)
|
Valuation allowance
|
|
|
24,409
|
|
|
14,288
|
|
|
—
|
Write-down of oil and natural gas properties
|
|
|
39,658
|
|
|
22,604
|
|
|
—
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
12,676
|
|
|
5,621
|
|
|
8,590
|
Change
in the fair value of share-based awards
|
|
|
1,277
|
|
|
461
|
|
|
1,045
|
Withdrawn proxy contest expenses
|
|
|
2
|
|
|
144
|
|
|
150
|
Adjusted
Income
|
|
$
|
6,102
|
|
$
|
185
|
|
$
|
2,845
|
Adjusted Income per
fully diluted common share
|
|
$
|
0.05
|
|
$
|
0.00
|
|
$
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
June 30,
2016
|
|
March 31,
2016
|
|
June 30,
2015
|
Net loss
|
|
$
|
(70,097)
|
|
$
|
(41,109)
|
|
$
|
(4,967)
|
Write-down of oil and natural gas properties
|
|
|
61,012
|
|
|
34,776
|
|
|
—
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
19,501
|
|
|
8,648
|
|
|
13,214
|
Change
in the fair value of share-based awards
|
|
|
2,628
|
|
|
1,225
|
|
|
2,086
|
Withdrawn proxy contest expenses
|
|
|
3
|
|
|
221
|
|
|
230
|
Acquisition expense
|
|
|
1,906
|
|
|
48
|
|
|
—
|
Income
tax benefit
|
|
|
—
|
|
|
—
|
|
|
(2,116)
|
Interest
expense
|
|
|
4,180
|
|
|
5,491
|
|
|
5,106
|
Depreciation, depletion and amortization
|
|
|
16,698
|
|
|
16,129
|
|
|
18,011
|
Accretion expense
|
|
|
395
|
|
|
180
|
|
|
134
|
Adjusted
EBITDA
|
|
$
|
36,226
|
|
$
|
25,609
|
|
$
|
31,698
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the second quarter of 2016 was
$29.0 million and is reconciled to
operating cash flow in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
June 30,
2016
|
|
March 31,
2016
|
|
June 30,
2015
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(70,097)
|
|
$
|
(41,109)
|
|
$
|
(4,967)
|
Adjustments to
reconcile net loss to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
16,698
|
|
|
16,129
|
|
|
18,011
|
Write-down of oil and natural gas properties
|
|
|
61,012
|
|
|
34,776
|
|
|
—
|
Accretion expense
|
|
|
395
|
|
|
180
|
|
|
134
|
Amortization of non-cash debt related items
|
|
|
780
|
|
|
781
|
|
|
780
|
Deferred
income tax (benefit) expense
|
|
|
—
|
|
|
—
|
|
|
(2,116)
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
19,501
|
|
|
8,648
|
|
|
13,214
|
Non-cash
expense related to equity share-based awards
|
|
|
(1,253)
|
|
|
392
|
|
|
(754)
|
Change
in the fair value of liability share-based awards
|
|
|
1,965
|
|
|
709
|
|
|
1,607
|
Discretionary cash
flow
|
|
$
|
29,001
|
|
$
|
20,506
|
|
$
|
25,909
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital
|
|
|
(6,974)
|
|
|
5,582
|
|
|
438
|
Payments
to settle asset retirement obligations
|
|
|
(158)
|
|
|
(161)
|
|
|
(2,163)
|
Payments
to settle vested liability share-based awards
|
|
|
(493)
|
|
|
(9,807)
|
|
|
(326)
|
Net cash provided by
operating activities
|
|
$
|
21,376
|
|
$
|
16,120
|
|
$
|
23,858
|
Callon Petroleum
Company
Consolidated
Balance Sheets
(in thousands,
except par and per share values and share data)
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
ASSETS
|
|
Unaudited
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
207
|
|
$
|
1,224
|
Accounts
receivable
|
|
44,460
|
|
|
39,624
|
Fair value of
derivatives
|
|
5,537
|
|
|
19,943
|
Other current
assets
|
|
1,766
|
|
|
1,461
|
Total current
assets
|
|
51,970
|
|
|
62,252
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
|
|
Evaluated properties
|
|
2,530,978
|
|
|
2,335,223
|
Less
accumulated depreciation, depletion, amortization and
impairment
|
|
(1,883,806)
|
|
|
(1,756,018)
|
Net oil
and natural gas properties
|
|
647,172
|
|
|
579,205
|
Unevaluated properties
|
|
379,605
|
|
|
132,181
|
Total oil and natural
gas properties
|
|
1,026,777
|
|
|
711,386
|
Other property and
equipment, net
|
|
9,971
|
|
|
7,700
|
Restricted
investments
|
|
3,323
|
|
|
3,309
|
Deferred financing
costs
|
|
3,076
|
|
|
3,642
|
Fair value of
derivatives
|
|
60
|
|
|
—
|
Other assets,
net
|
|
413
|
|
|
305
|
Total
assets
|
$
|
1,095,590
|
|
$
|
788,594
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
71,960
|
|
$
|
70,970
|
Accrued
interest
|
|
6,258
|
|
|
5,989
|
Cash-settleable
restricted stock unit awards
|
|
5,168
|
|
|
10,128
|
Asset retirement
obligations
|
|
3,933
|
|
|
790
|
Fair value of
derivatives
|
|
7,491
|
|
|
—
|
Total current
liabilities
|
|
94,810
|
|
|
87,877
|
Senior secured
revolving credit facility
|
|
40,000
|
|
|
40,000
|
Secured second lien
term loan, net of unamortized deferred financing costs
|
|
289,559
|
|
|
288,565
|
Asset retirement
obligations
|
|
2,164
|
|
|
4,317
|
Cash-settleable
restricted stock unit awards
|
|
4,141
|
|
|
4,877
|
Fair value of
derivatives
|
|
6,313
|
|
|
—
|
Other long-term
liabilities
|
|
286
|
|
|
200
|
Total
liabilities
|
|
437,273
|
|
|
425,836
|
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 1,578,948
shares outstanding, respectively
|
|
15
|
|
|
16
|
Common stock, $0.01
par value, 300,000,000 and 150,000,000 shares authorized,
respectively; 131,090,644 and 80,087,148 shares outstanding,
respectively
|
|
1,311
|
|
|
801
|
Capital in excess of
par value
|
|
1,112,873
|
|
|
702,970
|
Accumulated
deficit
|
|
(455,882)
|
|
|
(341,029)
|
Total stockholders'
equity
|
|
658,317
|
|
|
362,758
|
Total liabilities and
stockholders' equity
|
$
|
1,095,590
|
|
$
|
788,594
|
Callon Petroleum
Company
Consolidated
Statements of Operations
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
40,555
|
|
$
|
36,093
|
|
$
|
67,998
|
|
$
|
64,002
|
Natural
gas sales
|
|
|
4,590
|
|
|
3,149
|
|
|
7,845
|
|
|
5,631
|
Total operating
revenues
|
|
|
45,145
|
|
|
39,242
|
|
|
75,843
|
|
|
69,633
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
7,311
|
|
|
6,575
|
|
|
14,268
|
|
|
13,534
|
Production taxes
|
|
|
2,455
|
|
|
2,952
|
|
|
4,675
|
|
|
5,217
|
Depreciation, depletion and amortization
|
|
|
16,293
|
|
|
17,587
|
|
|
32,015
|
|
|
35,691
|
General
and administrative
|
|
|
6,302
|
|
|
5,763
|
|
|
11,864
|
|
|
17,865
|
Accretion expense
|
|
|
395
|
|
|
134
|
|
|
575
|
|
|
343
|
Write-down of oil and natural gas properties
|
|
|
61,012
|
|
|
—
|
|
|
95,788
|
|
|
—
|
Rig
termination fee
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,641
|
Acquisition expense
|
|
|
1,906
|
|
|
—
|
|
|
1,954
|
|
|
—
|
Total operating
expenses
|
|
|
95,674
|
|
|
33,011
|
|
|
161,139
|
|
|
76,291
|
Income
(loss) from operations
|
|
|
(50,529)
|
|
|
6,231
|
|
|
(85,296)
|
|
|
(6,658)
|
Other (income)
expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net of capitalized amounts
|
|
|
4,180
|
|
|
5,106
|
|
|
9,671
|
|
|
9,964
|
Loss on
derivative contracts
|
|
|
15,484
|
|
|
8,249
|
|
|
16,416
|
|
|
5,820
|
Other
income, net
|
|
|
(96)
|
|
|
(41)
|
|
|
(177)
|
|
|
(85)
|
Total other
expense
|
|
|
19,568
|
|
|
13,314
|
|
|
25,910
|
|
|
15,699
|
Loss
before income taxes
|
|
|
(70,097)
|
|
|
(7,083)
|
|
|
(111,206)
|
|
|
(22,357)
|
Income tax
benefit
|
|
|
—
|
|
|
(2,116)
|
|
|
—
|
|
|
(7,193)
|
Net loss
|
|
|
(70,097)
|
|
|
(4,967)
|
|
|
(111,206)
|
|
|
(15,164)
|
Preferred stock
dividends
|
|
|
(1,823)
|
|
|
(1,973)
|
|
|
(3,647)
|
|
|
(3,947)
|
Loss available
to common stockholders
|
|
$
|
(71,920)
|
|
$
|
(6,940)
|
|
$
|
(114,853)
|
|
$
|
(19,111)
|
Loss per
common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.61)
|
|
$
|
(0.11)
|
|
$
|
(1.14)
|
|
$
|
(0.31)
|
Diluted
|
|
$
|
(0.61)
|
|
$
|
(0.11)
|
|
$
|
(1.14)
|
|
$
|
(0.31)
|
Shares
used in computing loss per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
118,209
|
|
|
66,038
|
|
|
100,895
|
|
|
61,759
|
Diluted
|
|
|
118,209
|
|
|
66,038
|
|
|
100,895
|
|
|
61,759
|
Callon Petroleum
Company
Consolidated
Statements of Cash Flows
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(70,097)
|
|
$
|
(4,967)
|
|
$
|
(111,206)
|
|
$
|
(15,164)
|
Adjustments to
reconcile net loss to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
16,698
|
|
|
18,011
|
|
|
32,827
|
|
|
36,557
|
Write-down of oil and natural gas properties
|
|
|
61,012
|
|
|
—
|
|
|
95,788
|
|
|
—
|
Accretion expense
|
|
|
395
|
|
|
134
|
|
|
575
|
|
|
343
|
Amortization of non-cash debt related items
|
|
|
780
|
|
|
780
|
|
|
1,561
|
|
|
1,561
|
Deferred
income tax benefit
|
|
|
—
|
|
|
(2,116)
|
|
|
—
|
|
|
(7,193)
|
Net loss
on derivatives, net of settlements
|
|
|
19,501
|
|
|
13,214
|
|
|
28,149
|
|
|
21,129
|
Non-cash
expense related to equity share-based awards
|
|
|
(1,253)
|
|
|
(754)
|
|
|
(861)
|
|
|
(668)
|
Change
in the fair value of liability share-based awards
|
|
|
1,965
|
|
|
1,607
|
|
|
2,674
|
|
|
4,695
|
Payments
to settle asset retirement obligations
|
|
|
(158)
|
|
|
(2,163)
|
|
|
(319)
|
|
|
(1,905)
|
Changes
in operating assets and liabilities:
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(10,777)
|
|
|
(4,821)
|
|
|
(4,836)
|
|
|
(6,946)
|
Other current
assets
|
|
|
(885)
|
|
|
(536)
|
|
|
(305)
|
|
|
(85)
|
Current
liabilities
|
|
|
4,830
|
|
|
5,904
|
|
|
4,113
|
|
|
5,549
|
Change in other
long-term liabilities
|
|
|
75
|
|
|
100
|
|
|
86
|
|
|
100
|
Change in other
assets, net
|
|
|
(217)
|
|
|
(209)
|
|
|
(450)
|
|
|
(528)
|
Payments
to settle vested liability share-based awards related to
early
|
|
|
|
|
|
|
|
|
|
|
|
|
retirements
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,538)
|
Payments
to settle vested liability share-based awards
|
|
|
(493)
|
|
|
(326)
|
|
|
(10,300)
|
|
|
(3,925)
|
Net cash provided
by operating activities
|
|
|
21,376
|
|
|
23,858
|
|
|
37,496
|
|
|
29,982
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(24,505)
|
|
|
(60,067)
|
|
|
(75,280)
|
|
|
(129,050)
|
Acquisitions
|
|
|
(273,841)
|
|
|
—
|
|
|
(284,024)
|
|
|
(1,797)
|
Proceeds from sales
of mineral interests and equipment
|
|
|
23,631
|
|
|
54
|
|
|
23,631
|
|
|
326
|
Net cash used in
investing activities
|
|
|
(274,715)
|
|
|
(60,013)
|
|
|
(335,673)
|
|
|
(130,521)
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
|
|
98,000
|
|
|
43,000
|
|
|
143,000
|
|
|
103,000
|
Payments on senior
secured revolving credit facility
|
|
|
(58,000)
|
|
|
(5,000)
|
|
|
(143,000)
|
|
|
(63,000)
|
Payment of deferred
financing costs
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
Issuance of common
stock, net
|
|
|
205,858
|
|
|
—
|
|
|
300,807
|
|
|
65,546
|
Payment of preferred
stock dividends
|
|
|
(1,823)
|
|
|
(1,973)
|
|
|
(3,647)
|
|
|
(3,947)
|
Net cash provided
by financing activities
|
|
|
244,035
|
|
|
36,039
|
|
|
297,160
|
|
|
101,599
|
Net change in cash
and cash equivalents
|
|
|
(9,304)
|
|
|
(116)
|
|
|
(1,017)
|
|
|
1,060
|
Balance,
beginning of period
|
|
|
9,511
|
|
|
2,144
|
|
|
1,224
|
|
|
968
|
Balance,
end of period
|
|
$
|
207
|
|
$
|
2,028
|
|
$
|
207
|
|
$
|
2,028
|
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as
"discretionary cash flow," "Adjusted Income (Loss)," "Adjusted
G&A" and "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 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 Tuesday, August 9, 2016, to discuss second
quarter 2016 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
Tuesday, August 9, 2016, 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.
Alternatively, you may join by telephone using the following
numbers:
Toll
Free:
1-888-349-0096
Canada Toll
Free:
1-855-669-9657
International:
1-412-902-0125
Request to
join:
Callon Petroleum Company Earnings Call
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 the consummation of the
pending transactions, wells anticipated to be drilled and placed on
production, future levels of drilling activity and associated
production, the Company's 2016 guidance, capital budget amounts and
expected cash flows, reserve quantities and the present value
thereof, 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. Without limiting
the foregoing, forward-looking statements contained in this news
release specifically include the expectation of total reserve
potential and EUR. 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
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:
Joe Gatto
Chief Financial Officer, Senior Vice President and Treasurer
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-second-quarter-2016-results-300310672.html
SOURCE Callon Petroleum Company