NATCHEZ, Miss., Nov. 2, 2016 /PRNewswire/ --
PDF of this Release -
http://origin-qps.onstreammedia.com/origin/multivu_archive/ENR/3Q16CPEEarningsResults.pdf
Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company")
today reported results of operations for the three months ended
September 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 third quarter of
2016 and other recent data points include:
- Net daily production of 16,598 barrels of oil equivalent per
day ("BOE/d"), an increase of 23% compared to the second quarter of
2016
- GAAP income per diluted common share of $0.14 and Adjusted Income per fully diluted
common share, a non-GAAP financial measure(i), of
$0.09
- Closed the Plymouth Acquisition and related common stock
financing, expanding our WildHorse area footprint to over 20,000
net acres and total Midland Basin acreage to over 40,000 net
acres
- Continued strong performance from our initial Wolfcamp
A completion in Howard County (Silver City Unit A 01H), with
cumulative production of over 192,000 BOE (89% oil) in the first
110 days on production
- Commenced program development of the WildHorse area with a
two-well pad targeting both the Wolfcamp A and Lower Spraberry
zones in northwest Howard County
- Refinanced our Term Loan with the issuance of Senior Notes,
reducing our cost of capital and establishing a benchmark,
publicly-traded security for future financing opportunities
- Raised 2016 full year production guidance to a range of 15,250
– 15,550 BOE/d and reaffirmed operational capital guidance for 2016
of $140 million
"Our strong recent well results combined with the longer term
performance of our production base enable us to continue our track
record of sustained production growth within a restrained capital
program," commented Fred Callon,
Chairman and Chief Executive Officer. "Given our expanded portfolio
of drilling opportunities that deliver solid returns on investment
at less than $50 per barrel of oil,
combined with low leverage metrics and liquidity of almost
$500 million, we currently anticipate
adding a third horizontal drilling rig in early 2017 and are
preparing for a fourth rig in the second half of 2017. We forecast
this program would deliver approximately 30,000 BOE/d of annual
average production in 2018, while generating free cash flow by
mid-year 2018 based on our 2018 planning case assumptions of
$50 per barrel and a theoretical
increase of 15% in completed well costs to address the impact of
evolving completion designs and potential upward pressure on
service costs from anticipated increases in core Permian Basin
activity."
Operations Update
At September 30, 2016, we had 124
gross (98.0 net) horizontal wells producing from six established
flow units. Net daily production for the three months ended
September 30, 2016 grew approximately
70% to 16,598 BOE/d (approximately 76% oil) as compared to the same
period of 2015. Sequentially, we grew production more than 23%
compared to the second quarter of 2016.
For the three months ended September 30,
2016, we operated 1.6 horizontal drilling rigs, drilled 8
gross (5.4 net) horizontal wells, completed 11 gross (6.8 net)
horizontal wells, and placed 7 gross (5.2 net) horizontal wells on
production. As of September 30, 2016,
we had 3 gross (2.8 net) horizontal wells awaiting completion.
Well Activity Summary
The following table details well-related activity for the
quarter by focus area:
|
|
For the Three
Months Ended September 30, 2016
|
|
|
Drilled
|
|
Completed
|
|
Placed on
Production
|
|
Awaiting
Completion
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
WildHorse
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
1.0
|
|
—
|
|
—
|
|
Monarch
|
|
8
|
|
5.4
|
|
9
|
|
5.7
|
|
4
|
|
3.1
|
|
3
|
|
2.8
|
|
Ranger
|
|
—
|
|
—
|
|
2
|
|
1.1
|
|
2
|
|
1.1
|
|
—
|
|
—
|
|
Total
|
|
8
|
|
5.4
|
|
11
|
|
6.8
|
|
7
|
|
5.2
|
|
3
|
|
2.8
|
During the third quarter, we continued to focus on development
of two flow units within the Lower Spraberry in the Monarch area
while also progressing the infrastructure buildout of WildHorse in
preparation for program development with multi-well pads. The
following table highlights wells that achieved peak rates during
the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
Focus
Area
|
|
Completed
|
|
24-Hour
|
|
Production
|
|
Lateral
|
|
30-Day
|
|
Production
|
|
Lateral
|
|
Date
|
|
Well
|
|
(Zone)
|
|
Lateral
(ft)
|
|
IP
|
|
(%
oil)
|
|
Feet
|
|
IP
|
|
(%
oil)
|
|
Feet
|
|
07/10/2016
|
|
Kendra-Annie 11
22SH
|
|
Monarch
(LS)
|
|
7,917
|
|
919
|
|
89%
|
|
116
|
|
894
|
|
88%
|
|
113
|
|
07/07/2016
|
|
Pecan Acres 22A4
11SH
|
|
Monarch
(LS)
|
|
4,622
|
|
719
|
|
87%
|
|
155
|
|
768
|
|
87%
|
|
166
|
|
08/03/2016
|
|
Silver City Unit A
01H
|
|
WildHorse
(WCA)
|
|
7,363
|
|
2,459
|
|
91%
|
|
334
|
|
2,148
|
|
89%
|
|
292
|
|
|
|
(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.
|
In early October, our first Wolfcamp A well in the Monarch area
was placed on production in the Pecan Acres field in close
proximity to recent offsetting industry activity in this zone. The
Wolfcamp A represents our fifth producing flow unit in the Monarch
area, inclusive of the upper and lower benches of the Lower
Spraberry, the Middle Spraberry and the Wolfcamp B. This well was
drilled from a stacked two-well pad with a Lower Spraberry (upper
bench) well. Both wells are cleaning up and have not reached peak
rates.
We also completed two drilled, uncompleted wells in the Ranger
area that were acquired earlier this year as part of our AMI
transaction in western Reagan County. Our development activity in
the Ranger area had previously been focused on Lower Wolfcamp B,
and these wells expand our efforts to the Upper Wolfcamp B and
Wolfcamp A. Importantly, we utilized a new generation completion
design on these latest wells, with proppant loading approximating
2,000 pounds per foot combined with tighter stage spacing. Both
wells were placed online in late September and have not reached
peak rates.
Our first operated completion in the WildHorse area yielded
encouraging results with the Silver City Unit A 01H well achieving
24-Hour and 30-Day IP rates of 334 (91% oil) and 292 (89% oil)
BOE/d per 1,000 feet of completed lateral, respectively. This
Wolfcamp A well has produced over 192 MBOE in the first 110 days
since first production. As part of our newly initiated program
development of WildHorse, we recently finished drilling two wells
in offsetting acreage targeting both the Wolfcamp A and Lower
Spraberry zones from a two-well pad. The rig remains active on this
acreage, currently drilling two additional wells targeting both the
Wolfcamp A and Lower Spraberry zones from a stacked two-well
pad.
Capital Expenditures
For the three months ended September 30,
2016, we accrued $43.3 million
in operational capital expenditures, including facilities
expenditures of $4.5 million,
compared to $21.1 million in the
second quarter of 2016. Total capital expenditures, inclusive of
capitalized expenses, are detailed below on an accrual and cash
basis (in thousands):
|
|
Three Months Ended
September 30, 2016
|
|
|
Operational
Capital
|
|
Seismic &
Other
|
|
Capitalized
Interest
|
|
Capitalized
G&A
|
|
Total Capital
Expenditures
|
|
Cash basis
(a)
|
|
$
|
30,182
|
|
$
|
7,258
|
|
$
|
7,133
|
|
$
|
2,845
|
|
$
|
47,418
|
|
Timing adjustments
(b)
|
|
|
13,127
|
|
|
(535)
|
|
|
112
|
|
|
—
|
|
|
12,704
|
|
Non-cash
items
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,217
|
|
|
3,217
|
|
Accrual
(GAAP) basis
|
|
$
|
43,309
|
|
$
|
6,723
|
|
$
|
7,245
|
|
$
|
6,062
|
|
$
|
63,339
|
|
|
|
(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
|
|
|
September 30,
2016
|
|
June 30,
2016
|
|
September 30,
2015
|
|
Net
production:
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
1,153
|
|
|
948
|
|
|
689
|
|
Natural
gas (MMcf)
|
|
|
2,244
|
|
|
1,658
|
|
|
1,239
|
|
Total
production (MBOE)
|
|
|
1,527
|
|
|
1,224
|
|
|
896
|
|
Average
daily production (BOE/d)
|
|
|
16,598
|
|
|
13,451
|
|
|
9,739
|
|
% oil
(BOE basis)
|
|
|
76%
|
|
|
77%
|
|
|
77%
|
|
Oil and natural
gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Oil
revenue
|
|
$
|
49,095
|
|
$
|
40,555
|
|
$
|
30,582
|
|
Natural
gas revenue
|
|
|
6,832
|
|
|
4,590
|
|
|
3,734
|
|
Total
revenue
|
|
$
|
55,927
|
|
$
|
45,145
|
|
$
|
34,316
|
|
Impact
of cash-settled derivatives
|
|
|
4,091
|
|
|
4,017
|
|
|
9,789
|
|
Adjusted Total Revenue
(i)
|
|
$
|
60,018
|
|
$
|
49,162
|
|
$
|
44,105
|
Total Revenue. For the quarter ended September 30, 2016, Callon reported total
revenues of $55.9 million and total
revenues including cash-settled derivatives ("Adjusted Total
Revenue," a non-GAAP financial measure(i)) of
$60 million, including the
$4.1 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 16,598 BOE/d compared
to average daily production of 13,451 BOE/d in the second quarter
of 2016. Average realized prices, including and excluding the
effects of hedging, are detailed below.
Hedging impacts. For the quarter ended September 30, 2016, Callon recognized the
following hedging-related items (in thousands):
|
|
|
|
|
|
|
|
|
In
Thousands
|
|
Per
Unit
|
|
Oil derivatives
contracts
|
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
4,252
|
|
$
|
3.69
|
|
Net gain on fair
value adjustments
|
|
|
699
|
|
|
|
|
Total
net gain on oil derivatives contracts
|
|
$
|
4,951
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
derivatives contracts
|
|
|
|
|
|
|
|
Net loss on
settlements
|
|
$
|
(161)
|
|
$
|
(0.07)
|
|
Net gain on fair
value adjustments
|
|
|
345
|
|
|
|
|
Total
net gain on natural gas derivatives contracts
|
|
$
|
184
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
contracts
|
|
|
|
|
|
|
|
Net gain on
settlements
|
|
$
|
4,091
|
|
$
|
2.67
|
|
Net gain on fair
value adjustments
|
|
|
1,044
|
|
|
|
|
Total
net gain on total derivatives contracts
|
|
$
|
5,135
|
|
|
|
Average realized prices, including and excluding the impact of
cash settled derivatives during the third quarter, were as
follows:
|
|
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2016
|
|
Average realized
sales price
|
|
|
|
|
Oil (per
Bbl) (excluding impact of cash-settled derivatives)
|
|
$
|
42.58
|
|
Impact of cash-settled
derivatives
|
|
|
3.69
|
|
Oil (per
Bbl) (including impact of cash-settled derivatives)
|
|
$
|
46.27
|
|
|
|
|
|
Natural
gas (per Mcf) (excluding impact of cash-settled
derivatives)
|
|
$
|
3.04
|
|
Impact of cash-settled
derivatives
|
|
|
(0.07)
|
|
Natural
gas (per Mcf) (including impact of cash-settled
derivatives)
|
|
$
|
2.97
|
|
|
|
|
|
Total
(per BOE) (excluding impact of cash-settled derivatives)
|
|
$
|
36.63
|
|
Impact of cash-settled
derivatives
|
|
|
2.67
|
|
Total
(per BOE) (including impact of cash-settled derivatives)
|
|
$
|
39.30
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2016
|
|
June 30,
2016
|
|
September 30,
2015
|
|
Additional per BOE
data:
|
|
|
|
|
|
|
|
|
|
|
Sales
price, excluding impact of cash-settled derivatives
|
|
$
|
36.63
|
|
$
|
36.88
|
|
$
|
38.30
|
|
Sales
price, including impact of cash-settled derivatives
|
|
|
39.30
|
|
|
40.17
|
|
|
49.22
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
$
|
6.52
|
|
$
|
5.97
|
|
$
|
8.03
|
|
Production taxes
|
|
|
2.28
|
|
|
2.01
|
|
|
2.88
|
|
Depletion, depreciation and amortization
|
|
|
11.33
|
|
|
13.31
|
|
|
18.64
|
|
G&A
|
|
|
5.17
|
|
|
5.15
|
|
|
4.80
|
|
Adjusted
G&A - total (a)
|
|
|
2.96
|
|
|
3.55
|
|
|
4.63
|
|
Adjusted
G&A - cash component (b)
|
|
|
2.38
|
|
|
2.92
|
|
|
3.81
|
|
|
|
(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
September 30, 2016 was $6.52 per BOE, compared to LOE of $5.97 per BOE in the second quarter of 2016. The
increase in this metric was primarily related to higher saltwater
disposal and fuel and power expenses related to assets acquired
during 2016. We continue to make investments in infrastructure in
these areas to support our planned increases in drilling activity
and expect these investments to reduce our LOE in these areas over
time.
Production Taxes, including ad valorem taxes. Production
taxes were $2.28 per BOE in the third
quarter of 2016, representing approximately 6.2% of total revenue
before the impact of derivative settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
September 30, 2016 was $11.33 per BOE compared to $13.31 per BOE in the second quarter of 2016. The
write-down of our oil and natural gas properties recorded during
the second quarter 2016 reduced the amortizable base, while our
underlying reserve base continues to increase as we progress our
horizontal development program. Combined, these changes resulted in
the $1.98 per BOE reduction in
DD&A.
General and Administrative ("G&A"). G&A for
the third quarter of 2016 was $7.9
million, or $5.17 per BOE,
compared to $6.3 million, or
$5.15 per BOE, for the second quarter
of 2016. G&A, excluding certain non-cash incentive share-based
compensation valuation adjustments, ("Adjusted G&A", a non-GAAP
measure(i)) was $4.5
million, or $2.96 per BOE, for
the third quarter of 2016 compared to $4.3
million, or $3.55 per BOE, for
the second quarter of 2016. The cash component of Adjusted G&A
was $3.6 million, or $2.38 per BOE, for the third quarter of 2016
compared to $3.6 million, or
$2.92 per BOE, for the second quarter
of 2016.
For the third 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
|
|
$
|
3,637
|
|
$
|
—
|
|
$
|
3,637
|
|
Restricted stock share-based compensation
|
|
|
—
|
|
|
768
|
|
|
768
|
|
Change
in the fair value of liability share-based awards
|
|
|
—
|
|
|
3,372
|
|
|
3,372
|
|
Corporate depreciation & amortization
|
|
|
—
|
|
|
114
|
|
|
114
|
|
Total G&A
expense:
|
|
$
|
3,637
|
|
$
|
4,254
|
|
$
|
7,891
|
|
Adjusted
G&A (i)
|
|
|
|
|
|
|
|
|
|
|
Less:
Change in the fair value of liability share-based awards
|
|
|
|
|
|
|
|
$
|
(3,372)
|
|
Adjusted G&A –
total
|
|
|
|
|
|
|
|
|
4,519
|
|
Restricted stock share-based compensation
|
|
|
|
|
|
|
|
|
(768)
|
|
Corporate depreciation & amortization
|
|
|
|
|
|
|
|
|
(114)
|
|
Adjusted G&A –
cash component
|
|
|
|
|
|
|
|
$
|
3,637
|
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 $0.1 million
income tax expense for the three months ended September 30, 2016. At September 30, 2016 we had a valuation allowance
of $139.6 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.
A breakdown of the Company's anticipated 2016 operational plan
and associated expenditures is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
YTD
2016
|
|
Estimated 4th
Quarter
|
|
Total
|
|
Operational
activity (gross / net)
|
|
|
|
|
|
|
|
|
|
|
Drilled
wells
|
|
|
19 / 13.4
|
|
|
12 / 7.7
|
|
|
31 / 21.1
|
|
Completed wells
|
|
|
25 / 17.3
|
|
|
7 / 6.5
|
|
|
32 / 23.8
|
|
Wells
placed on production
|
|
|
20 / 14.7
|
|
|
10 / 6.5
|
|
|
30 / 21.2
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures (in millions, accrual basis)
|
|
|
|
|
|
|
|
|
|
|
Drilling
and completion
|
|
$
|
84.6
|
|
$
|
31.7
|
|
$
|
116.3
|
|
Facilities
|
|
|
14.7
|
|
|
9.0
|
|
|
23.7
|
|
Operational capital
expenditures
|
|
$
|
99.3
|
|
$
|
40.7
|
|
$
|
140.0
|
|
Seismic
|
|
|
3.4
|
|
|
0.7
|
|
|
4.1
|
|
Land and
other
|
|
|
5.8
|
|
|
0.3
|
|
|
6.1
|
|
Total capital
expenditures (excl. capitalized expenses)
|
|
$
|
108.5
|
|
$
|
41.7
|
|
$
|
150.2
|
2016 Guidance Update
|
|
Previous Full
Year
|
|
Updated Full
Year
|
|
|
2016
Guidance
|
|
2016
Guidance
|
|
Total production
(BOE/d)
|
|
14,500 -
15,500
|
|
15,250 -
15,550
|
|
%
oil
|
|
76% - 80%
|
|
75% - 77%
|
|
Expenses (per
BOE)
|
|
|
|
|
|
LOE,
including workovers
|
|
$5.75 -
$6.25
|
|
$6.00 -
$6.50
|
|
Production taxes, including ad valorem (% unhedged
revenue)
|
|
7%
|
|
7%
|
|
Adjusted
G&A (a)
|
|
$3.25 -
$3.75
|
|
$3.15 -
$3.40
|
|
Adjusted
G&A - cash component (b)
|
|
$2.35 -
$2.85
|
|
$2.50 -
$2.75
|
|
Total capital
expenditures
|
|
|
|
|
|
Accrual
basis ($MM)
|
|
$140
|
|
$140
|
|
|
|
(a)
|
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.
|
|
(b)
|
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 November 2, 2016:
|
|
For the Remainder
of
|
|
For the Full Year
of
|
|
Oil
contracts
|
|
2016
|
|
2017
|
|
Swap contracts
(WTI)
|
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
184
|
|
|
—
|
|
Weighted
average price per Bbl
|
|
$
|
58.23
|
|
$
|
—
|
|
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)
|
|
|
184
|
|
|
—
|
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
65.00
|
|
$
|
—
|
|
Floor (long put
option)
|
|
$
|
55.00
|
|
$
|
—
|
|
Short put
option
|
|
$
|
40.33
|
|
$
|
—
|
|
Collar contracts
(WTI, two-way collars)
|
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
184
|
|
|
1,533
|
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
|
Ceiling (short
call)
|
|
$
|
46.50
|
|
$
|
58.15
|
|
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)
|
|
|
368
|
|
|
—
|
|
Weighted
average price per Bbl
|
|
$
|
0.17
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Natural gas
contracts
|
|
|
|
|
|
|
|
Swap contracts
(Henry Hub)
|
|
|
|
|
|
|
|
Total
volume (BBtu)
|
|
|
552
|
|
|
—
|
|
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
|
Income (Loss) Available to Common Shareholders. The
Company reported a net income available to common shareholders of
$19.3 million in the third quarter of
2016 and Adjusted Income available to common shareholders of
$12.9 million, or $0.09 per diluted share. The following tables
reconcile to the related GAAP measure the Company's income (loss)
available to common stockholders to Adjusted Income and the
Company's net income (loss) to Adjusted EBITDA (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2016
|
|
June 30,
2016
|
|
September 30,
2015
|
|
Income (loss)
available to common stockholders
|
|
$
|
19,315
|
|
$
|
(71,920)
|
|
$
|
(113,779)
|
|
Change
in valuation allowance
|
|
|
(7,907)
|
|
|
24,409
|
|
|
68,818
|
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
39,658
|
|
|
56,746
|
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
(679)
|
|
|
12,676
|
|
|
(8,771)
|
|
Change
in the fair value of share-based awards
|
|
|
2,192
|
|
|
1,277
|
|
|
37
|
|
Withdrawn proxy contest expenses
|
|
|
—
|
|
|
2
|
|
|
65
|
|
Adjusted
Income
|
|
$
|
12,921
|
|
$
|
6,102
|
|
$
|
3,116
|
|
Adjusted Income per
fully diluted common share
|
|
$
|
0.09
|
|
$
|
0.05
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2016
|
|
June 30,
2016
|
|
September 30,
2015
|
|
Net income
(loss)
|
|
$
|
21,139
|
|
$
|
(70,097)
|
|
$
|
(111,805)
|
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
61,012
|
|
|
87,301
|
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
(1,044)
|
|
|
19,501
|
|
|
(13,494)
|
|
Change
in the fair value of share-based awards
|
|
|
4,150
|
|
|
2,628
|
|
|
655
|
|
Withdrawn proxy contest expenses
|
|
|
—
|
|
|
3
|
|
|
100
|
|
Acquisition expense
|
|
|
456
|
|
|
1,906
|
|
|
(3)
|
|
Income
tax (benefit) expense
|
|
|
(62)
|
|
|
—
|
|
|
45,667
|
|
Interest
expense
|
|
|
831
|
|
|
4,180
|
|
|
5,603
|
|
Depreciation, depletion and amortization
|
|
|
17,733
|
|
|
16,698
|
|
|
16,026
|
|
Accretion expense
|
|
|
187
|
|
|
395
|
|
|
142
|
|
Adjusted
EBITDA
|
|
$
|
43,390
|
|
$
|
36,226
|
|
$
|
30,192
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the third quarter of 2016 was
$42.7 million and is reconciled to
operating cash flow in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
September 30,
2016
|
|
June 30,
2016
|
|
September 30,
2015
|
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
21,139
|
|
$
|
(70,097)
|
|
$
|
(111,805)
|
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
17,733
|
|
|
16,698
|
|
|
16,026
|
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
61,012
|
|
|
87,301
|
|
Accretion expense
|
|
|
187
|
|
|
395
|
|
|
142
|
|
Amortization of non-cash debt related items
|
|
|
810
|
|
|
780
|
|
|
781
|
|
Deferred
income tax expense
|
|
|
(62)
|
|
|
—
|
|
|
45,667
|
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
(1,044)
|
|
|
19,501
|
|
|
(13,494)
|
|
Non-cash
expense related to equity share-based awards
|
|
|
608
|
|
|
(1,253)
|
|
|
368
|
|
Change
in the fair value of liability share-based awards
|
|
|
3,371
|
|
|
1,965
|
|
|
64
|
|
Discretionary cash
flow
|
|
$
|
42,742
|
|
$
|
29,001
|
|
$
|
25,050
|
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital
|
|
|
2,927
|
|
|
(6,974)
|
|
|
1,639
|
|
Acquisition deposit
|
|
|
(32,700)
|
|
|
—
|
|
|
—
|
|
Payments
to settle asset retirement obligations
|
|
|
(576)
|
|
|
(158)
|
|
|
(1,142)
|
|
Payments
to settle vested liability share-based awards
|
|
|
—
|
|
|
(493)
|
|
|
—
|
|
Net cash provided by
operating activities
|
|
$
|
12,393
|
|
$
|
21,376
|
|
$
|
25,547
|
|
Callon Petroleum
Company
|
|
Consolidated
Balance Sheets
|
|
(in thousands,
except par and per share values and share data)
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
ASSETS
|
|
Unaudited
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
325,885
|
|
$
|
1,224
|
|
Accounts
receivable
|
|
56,172
|
|
|
39,624
|
|
Fair value of
derivatives
|
|
3,502
|
|
|
19,943
|
|
Other current
assets
|
|
1,712
|
|
|
1,461
|
|
Total current
assets
|
|
387,271
|
|
|
62,252
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
|
|
|
Evaluated properties
|
|
2,593,798
|
|
|
2,335,223
|
|
Less
accumulated depreciation, depletion, amortization and
impairment
|
|
(1,901,102)
|
|
|
(1,756,018)
|
|
Net oil
and natural gas properties
|
|
692,696
|
|
|
579,205
|
|
Unevaluated properties
|
|
393,875
|
|
|
132,181
|
|
Total oil and natural
gas properties
|
|
1,086,571
|
|
|
711,386
|
|
Other property and
equipment, net
|
|
12,816
|
|
|
7,700
|
|
Restricted
investments
|
|
3,329
|
|
|
3,309
|
|
Deferred financing
costs
|
|
3,431
|
|
|
3,642
|
|
Fair value of
derivatives
|
|
57
|
|
|
—
|
|
Acquisition
deposit
|
|
32,700
|
|
|
—
|
|
Other assets,
net
|
|
1,429
|
|
|
305
|
|
Total
assets
|
$
|
1,527,604
|
|
$
|
788,594
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
99,026
|
|
$
|
70,970
|
|
Accrued
interest
|
|
5,950
|
|
|
5,989
|
|
Cash-settleable
restricted stock unit awards
|
|
8,269
|
|
|
10,128
|
|
Asset retirement
obligations
|
|
3,529
|
|
|
790
|
|
Deferred tax
liability
|
|
42
|
|
|
—
|
|
Fair value of
derivatives
|
|
7,786
|
|
|
—
|
|
Total current
liabilities
|
|
124,602
|
|
|
87,877
|
|
Senior secured
revolving credit facility
|
|
—
|
|
|
40,000
|
|
Secured second lien
term loan, net of unamortized deferred financing costs
|
|
290,085
|
|
|
288,565
|
|
Asset retirement
obligations
|
|
1,934
|
|
|
4,317
|
|
Cash-settleable
restricted stock unit awards
|
|
7,042
|
|
|
4,877
|
|
Fair value of
derivatives
|
|
2,936
|
|
|
—
|
|
Other long-term
liabilities
|
|
286
|
|
|
200
|
|
Total
liabilities
|
|
426,885
|
|
|
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;
161,036,233 and 80,087,148 shares outstanding,
respectively
|
|
1,610
|
|
|
801
|
|
Capital in excess of
par value
|
|
1,535,661
|
|
|
702,970
|
|
Accumulated
deficit
|
|
(436,567)
|
|
|
(341,029)
|
|
Total stockholders'
equity
|
|
1,100,719
|
|
|
362,758
|
|
Total liabilities and
stockholders' equity
|
$
|
1,527,604
|
|
$
|
788,594
|
|
Callon Petroleum
Company
|
|
Consolidated
Statements of Operations
|
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
49,095
|
|
$
|
30,582
|
|
$
|
117,093
|
|
$
|
94,584
|
|
Natural
gas sales
|
|
|
6,832
|
|
|
3,734
|
|
|
14,677
|
|
|
9,365
|
|
Total operating
revenues
|
|
|
55,927
|
|
|
34,316
|
|
|
131,770
|
|
|
103,949
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
9,961
|
|
|
7,194
|
|
|
24,229
|
|
|
20,728
|
|
Production taxes
|
|
|
3,478
|
|
|
2,583
|
|
|
8,153
|
|
|
7,800
|
|
Depreciation, depletion and amortization
|
|
|
17,303
|
|
|
16,704
|
|
|
49,318
|
|
|
52,395
|
|
General
and administrative
|
|
|
7,891
|
|
|
4,302
|
|
|
19,755
|
|
|
22,167
|
|
Accretion expense
|
|
|
187
|
|
|
142
|
|
|
762
|
|
|
485
|
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
87,301
|
|
|
95,788
|
|
|
87,301
|
|
Rig
termination fee
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,641
|
|
Acquisition expense
|
|
|
456
|
|
|
—
|
|
|
2,410
|
|
|
—
|
|
Total operating
expenses
|
|
|
39,276
|
|
|
118,226
|
|
|
200,415
|
|
|
194,517
|
|
Income
(loss) from operations
|
|
|
16,651
|
|
|
(83,910)
|
|
|
(68,645)
|
|
|
(90,568)
|
|
Other (income)
expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net of capitalized amounts
|
|
|
831
|
|
|
5,603
|
|
|
10,502
|
|
|
15,567
|
|
(Gain)
loss on derivative contracts
|
|
|
(5,135)
|
|
|
(23,283)
|
|
|
11,281
|
|
|
(17,463)
|
|
Other
income, net
|
|
|
(122)
|
|
|
(92)
|
|
|
(299)
|
|
|
(177)
|
|
Total other (income)
expense
|
|
|
(4,426)
|
|
|
(17,772)
|
|
|
21,484
|
|
|
(2,073)
|
|
Income
(loss) before income taxes
|
|
|
21,077
|
|
|
(66,138)
|
|
|
(90,129)
|
|
|
(88,495)
|
|
Income tax (benefit)
expense
|
|
|
(62)
|
|
|
45,667
|
|
|
(62)
|
|
|
38,474
|
|
Net income
(loss)
|
|
|
21,139
|
|
|
(111,805)
|
|
|
(90,067)
|
|
|
(126,969)
|
|
Preferred stock
dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
(5,471)
|
|
|
(5,921)
|
|
Income (loss)
available to common stockholders
|
|
$
|
19,315
|
|
$
|
(113,779)
|
|
$
|
(95,538)
|
|
$
|
(132,890)
|
|
Income (loss)
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
$
|
(1.72)
|
|
$
|
(0.85)
|
|
$
|
(2.10)
|
|
Diluted
|
|
$
|
0.14
|
|
$
|
(1.72)
|
|
$
|
(0.85)
|
|
$
|
(2.10)
|
|
Shares
used in computing income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
136,983
|
|
|
66,277
|
|
|
112,925
|
|
|
63,265
|
|
Diluted
|
|
|
137,483
|
|
|
66,277
|
|
|
112,925
|
|
|
63,265
|
|
Callon Petroleum
Company
|
|
Consolidated
Statements of Cash Flows
|
|
(Unaudited; in
thousands)
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
21,139
|
|
$
|
(111,805)
|
|
$
|
(90,067)
|
|
$
|
(126,969)
|
|
Adjustments to
reconcile net loss to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
17,733
|
|
|
16,026
|
|
|
50,560
|
|
|
52,583
|
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
87,301
|
|
|
95,788
|
|
|
87,301
|
|
Accretion expense
|
|
|
187
|
|
|
142
|
|
|
762
|
|
|
485
|
|
Amortization of non-cash debt related items
|
|
|
810
|
|
|
781
|
|
|
2,371
|
|
|
2,342
|
|
Deferred
income tax (benefit) expense
|
|
|
(62)
|
|
|
45,667
|
|
|
(62)
|
|
|
38,474
|
|
Net loss
on derivatives, net of settlements
|
|
|
(1,044)
|
|
|
(13,494)
|
|
|
27,105
|
|
|
7,635
|
|
Non-cash
expense related to equity share-based awards
|
|
|
608
|
|
|
368
|
|
|
(253)
|
|
|
(300)
|
|
Change
in the fair value of liability share-based awards
|
|
|
3,371
|
|
|
64
|
|
|
6,045
|
|
|
4,759
|
|
Payments
to settle asset retirement obligations
|
|
|
(576)
|
|
|
(1,142)
|
|
|
(895)
|
|
|
(3,047)
|
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(11,608)
|
|
|
(332)
|
|
|
(16,444)
|
|
|
(7,278)
|
|
Other current
assets
|
|
|
54
|
|
|
116
|
|
|
(251)
|
|
|
31
|
|
Current
liabilities
|
|
|
15,702
|
|
|
906
|
|
|
19,815
|
|
|
6,455
|
|
Acquisition
deposit
|
|
|
(32,700)
|
|
|
—
|
|
|
(32,700)
|
|
|
—
|
|
Change in other
long-term liabilities
|
|
|
—
|
|
|
—
|
|
|
86
|
|
|
100
|
|
Change in other
assets, net
|
|
|
(1,221)
|
|
|
949
|
|
|
(1,671)
|
|
|
421
|
|
Payments
to settle vested liability share-based awards related to
early
|
|
|
|
|
|
|
|
|
|
|
|
|
|
retirements
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,538)
|
|
Payments
to settle vested liability share-based awards
|
|
|
—
|
|
|
—
|
|
|
(10,300)
|
|
|
(3,925)
|
|
Net cash provided
by operating activities
|
|
|
12,393
|
|
|
25,547
|
|
|
49,889
|
|
|
55,529
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(47,418)
|
|
|
(46,649)
|
|
|
(122,698)
|
|
|
(175,699)
|
|
Acquisitions
|
|
|
(18,033)
|
|
|
(1,052)
|
|
|
(302,057)
|
|
|
(2,849)
|
|
Proceeds from sales
of mineral interests and equipment
|
|
|
(708)
|
|
|
22
|
|
|
22,923
|
|
|
348
|
|
Net cash used in
investing activities
|
|
|
(66,159)
|
|
|
(47,679)
|
|
|
(401,832)
|
|
|
(178,200)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
|
|
74,000
|
|
|
27,000
|
|
|
217,000
|
|
|
130,000
|
|
Payments on senior
secured revolving credit facility
|
|
|
(114,000)
|
|
|
(3,000)
|
|
|
(257,000)
|
|
|
(66,000)
|
|
Payment of deferred
financing costs
|
|
|
(640)
|
|
|
—
|
|
|
(640)
|
|
|
—
|
|
Issuance of common
stock, net
|
|
|
421,908
|
|
|
—
|
|
|
722,715
|
|
|
65,546
|
|
Payment of preferred
stock dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
(5,471)
|
|
|
(5,921)
|
|
Net cash provided
by financing activities
|
|
|
379,444
|
|
|
22,026
|
|
|
676,604
|
|
|
123,625
|
|
Net change in cash
and cash equivalents
|
|
|
325,678
|
|
|
(106)
|
|
|
324,661
|
|
|
954
|
|
Balance,
beginning of period
|
|
|
207
|
|
|
2,028
|
|
|
1,224
|
|
|
968
|
|
Balance,
end of period
|
|
$
|
325,885
|
|
$
|
1,922
|
|
$
|
325,885
|
|
$
|
1,922
|
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 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 Thursday, November 3, 2016, to discuss third
quarter 2016 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
|
Date/Time:
|
Thursday, November 3,
2016, 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:
|
1-888-349-0096
|
|
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 wells anticipated to be
drilled and placed on production; future levels of drilling
activity and associated production and cash flow expectations; the
Company's 2016 guidance and capital expenditure forecast; 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, Finance
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-third-quarter-2016-results-300356155.html
SOURCE Callon Petroleum Company