NATCHEZ, Miss., Feb. 27, 2017 /PRNewswire/ --
Click here for a PDF version of this release.
Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company")
today reported results of operations for the three months and
full-year ended December 31,
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 full-year and
fourth quarter 2016, and other recent data points include:
- Full-year 2016 production of 15.2 MBOE/d (77% oil), an increase
of 59% over 2015 volumes
- Fourth quarter 2016 production of 18.4 MBOE/d (76% oil), a
sequential quarterly increase of 11%
- Year-end proved reserves of 91.6 MMBOE (78% oil), a yearly
increase of 69%
- Organic reserve replacement(i) of 311% of 2016
production at a "Drill-Bit" finding and development cost
concept(i) of $8.77 per
BOE on a two-stream basis
- GAAP loss per diluted common share of $0.02 and Adjusted Income per fully diluted
common share, a non-GAAP financial measure(i), of
$0.08
- Entered into agreements for multiple acquisitions during 2016,
forming two new core operating areas and increasing our total
acreage footprint by approximately 41,000 net acres
- Currently operating three horizontal rigs, including two in
WildHorse and one in Monarch
- Increased full-year 2017 production guidance to a range of 22.5
– 25.5 MBOE/d, an increase of approximately 60% over 2016 based on
the midpoint of guidance
"Callon delivered exceptional growth in our producing assets in
2016, with a nearly 60% increase in daily production and 70%
increase in proved reserves," commented Fred Callon, Chairman and Chief Executive
Officer. "The strength of a capital efficient operational base,
combined with our solid financial position, allowed us to stay on
our front foot throughout the year and ultimately enter into
acquisition agreements that tripled our acreage position in the
Permian Basin on an accretive basis. We are now entering a period
that will be characterized by drill-bit growth, planning to
increase our horizontal development program to five rigs in both
the Midland and Delaware Basins by early 2018. Our 2017 drilling
program will be active in all four of our core operating areas as
we prioritize top-tier cash returns in our portfolio, without the
need to manage onerous drilling obligations. In the near-term, we
are on the cusp of unlocking the value of our newly acquired
WildHorse position after investing in facilities for efficient
development and adding a second rig to this position last month. We
look forward to accelerating the value proposition in a similar
manner in the Spur area with a rig starting by mid-year. Overall,
we currently expect our operations to produce another year of
production growth approaching 60% in 2017 while maintaining the
financial strength required to navigate any potential headwinds in
2017 and beyond. With our existing portfolio of delineated
locations in core, unconventional shale plays, Callon is
well-positioned to deliver leading production and cash flow growth
per share, as well as additional upside in emerging zones across
the entire Permian Basin."
Operations Update
At December 31, 2016, we had 148
gross (112.5 net) horizontal wells producing from six established
flow units in the Midland Basin. Net daily production for the three
months ended December 31, 2016 grew
approximately 73% to 18.4 thousand barrels of oil equivalent per
day ("MBOE/d") (approximately 76% oil) as compared to the same
period of 2015. Sequentially, we grew production by approximately
11% compared to the third quarter of 2016.
For the three months ended December 31,
2016, we operated two horizontal drilling rigs, drilling 10
gross (7.4 net) horizontal wells in both the Monarch and WildHorse
areas. We placed 10 gross (6.9 net) horizontal wells on production
in the quarter, all of which were located in our Monarch area.
Well Activity Summary
The following table details well-related activity for the
quarter by operating area:
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For the Three
Months Ended December 31, 2016
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Completed/
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Drilled
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On
Production(a)
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Awaiting
Completion
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Monarch horizontal
wells
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5
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2.9
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10
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6.9
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3
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1.4
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WildHorse horizontal
wells
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5
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4.5
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—
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—
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3
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2.8
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Total
Midland Basin wells
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10
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7.4
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10
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6.9
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6
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4.2
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(a)
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Wells turned to
production batteries. Includes wells drilled prior to the fourth
quarter of 2016.
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During the fourth quarter, we continued to focus on the
development of two flow units within the Lower Spraberry in the
Monarch area, and also expanded our development to include the
Wolfcamp A zone which was placed on production in early
October 2016. The following table
highlights wells that achieved peak rates during the period,
expressed in absolute barrels of oil equivalent per day ("BOE/d")
and production rates per 1,000 feet of completed lateral:
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30-Day
Average
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24-Hour Peak
IP
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Peak
IP
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(BOE/d;
Two-stream) (a)
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(BOE/d;
Two-stream)
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24-Hour
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Peak
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Per
1,000'
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Peak
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Per
1,000'
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IP
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Focus
Area
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Completed
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24-Hour
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Production
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Lateral
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30-Day
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Production
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Lateral
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Date
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Well
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(Zone)
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Lateral
(ft)
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IP
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(%
oil)
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Feet
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IP
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(%
oil)
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Feet
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11/20/2016
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Casselman
40-6LL
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Monarch
(LLS)
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4,473
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987
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76%
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221
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760
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78%
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170
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11/20/2016
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Casselman
40-8LL
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Monarch
(LLS)
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4,623
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968
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78%
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209
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760
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82%
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164
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11/22/2016
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Pecan Acres
23
PSA 2 09SH
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Monarch
(LLS)
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9,206
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1,411
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88%
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153
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1,142
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86%
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124
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12/01/2016
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Casselman 40
07UL
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Monarch
(ULS)
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4,473
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1,030
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86%
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230
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883
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86%
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198
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12/05/2016
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Pecan Acres
23
PSA 2 16AH
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Monarch
(WCA)
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9,234
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1,440
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89%
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156
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1,352
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89%
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146
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12/06/2016
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Kendra-Kristen 4
24SH
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Monarch
(LLS)
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9,642
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1,797
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93%
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186
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1,255
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92%
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130
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12/16/2016
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Kendra-Kristen 3
23SH
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Monarch
(ULS)
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9,678
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1,296
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93%
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134
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1,101
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92%
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114
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12/25/2016
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Kendra-Kristen 5
25SH
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Monarch
(ULS)
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9,402
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1,500
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93%
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160
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1,167
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92%
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124
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01/05/2017
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Kendra PSA 1
216LL
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Monarch
(LLS)
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10,061
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1,747
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90%
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174
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1,381
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90%
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137
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01/05/2017
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Kendra PSA 1
218LL
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Monarch
(LLS)
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10,343
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1,517
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89%
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147
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1,289
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90%
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125
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(a)
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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.
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We are encouraged with the performance of the first Wolfcamp A
well in the Monarch focus area. The Pecan Acres PSA 2 16AH was
drilled from a stacked two-well pad with a ULS well and achieved a
Peak 30-Day IP of over 1,350 BOE/d (89% oil), further demonstrating
the high quality of targeted flow units for multi-zone development
in the future. This well represents our fifth producing flow unit
in the Monarch area, inclusive of the Upper and Lower benches of
the Lower Spraberry (the "ULS" and "LLS", respectively), the Middle
Spraberry and the Wolfcamp B. Additionally, we drilled and
completed our longest laterals to date in our Carpe Diem field targeting the LLS with drilled
laterals averaging nearly 11,500 ft. and average Peak 30-Day IPs of
approximately 1,350 BOE (90% oil).
We also drilled five gross wells in WildHorse in the fourth
quarter as we commenced our program development of this new core
operating unit. We recently completed our first four wells during
January 2017, including a two-well,
staggered Wolfcamp A and Lower Spraberry pad in the Sidewinder
field in northwest Howard County, and a stacked Wolfcamp A and
Lower Spraberry pad located approximately 10 miles south of
Sidewinder in the Maverick field. These four wells are in various
stages of flowback and continue to climb towards peak
rates.
Callon is currently operating three horizontal rigs, two of
which are running in the WildHorse area. We initiated our pad
development program in this area in late 2016 and recently
accelerated our activity with the addition of a second rig in
January 2017 after making substantial
progress on our infrastructure investment plan. Both rigs are
currently drilling in the Fairway field located in central Howard
County. The rig on the western side of Fairway is drilling a
three-well, stacked pad targeting the Lower Spraberry, Wolfcamp A
and Wolfcamp B zones, which we expect to complete in March 2017. The rig on the eastern side of
Fairway is drilling a two-well pad targeting the Wolfcamp A, which
we expect to complete in April 2017.
Our third horizontal rig continues to be focused in Monarch before
moving to Reagan County in the Ranger unit in the second
quarter.
We are also progressing our plans for program development in our
recently acquired acreage in the Delaware Basin, which has been named the Spur
operating area. We are currently flowing back a recently completed
10,000' lateral well targeting the Lower Wolfcamp A, the Corbets
34-149 2WA, and early time performance is in-line with our type
curve expectations. We are also preparing to complete a 10,000'
lateral well targeting the Wolfcamp B in an offsetting drilling
unit. Following the completion of upgrades to existing
infrastructure, we plan to add a dedicated horizontal drilling rig
to the Spur operating area by mid-year 2017, with the potential for
incremental drilling activity in the Delaware Basin in 2018.
Capital Expenditures
For the three months ended December 31,
2016, we accrued $43.3 million
in operational capital expenditures, including facilities
expenditures of $11.4 million, equal
to $43.3 million accrued in the third
quarter of 2016. Total capital expenditures, inclusive of
capitalized expenses, are detailed below on an accrual and cash
basis (in thousands):
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Three Months Ended
December 31, 2016
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Operational
Capital
Expenditures
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Seismic &
Other
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Capitalized
Interest
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Capitalized
G&A
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Total Capital
Expenditures
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Cash basis
(a)
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$
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53,358
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$
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3,625
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$
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6,699
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$
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3,652
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$
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67,334
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Timing adjustments
(b)
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(10,030)
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754
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1
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—
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(9,275)
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Non-cash
items
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—
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—
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—
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1,352
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1,352
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Accrual
(GAAP) basis
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$
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43,328
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$
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4,379
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$
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6,700
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$
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5,004
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$
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59,411
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(a)
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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.
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(b)
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Includes timing
adjustments related to cash disbursements in the current period for
capital expenditures incurred in the prior period.
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Operating and Financial Results
The following table presents summary information for the periods
indicated:
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Three Months
Ended
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December 31,
2016
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|
September 30,
2016
|
|
December 31,
2015
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Net
production
|
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Oil
(MBbls)
|
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1,287
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|
1,153
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|
777
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Natural
gas (MMcf)
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2,413
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2,244
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1,188
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Total
production (MBOE)
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1,689
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|
1,527
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|
975
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Average
daily production (BOE/d)
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18,359
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16,598
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10,598
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% oil
(BOE basis)
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76%
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76%
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80%
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Oil and natural
gas revenues (in thousands)
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Oil
revenue
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$
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60,559
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$
|
49,095
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$
|
30,582
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Natural
gas revenue
|
|
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8,522
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6,832
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2,981
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Total
revenue
|
|
$
|
69,081
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|
$
|
55,927
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|
$
|
33,563
|
Impact
of cash-settled derivatives
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2,079
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4,091
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9,918
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Adjusted Total Revenue
(i)
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$
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71,160
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$
|
60,018
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$
|
43,481
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Total Revenue. For the quarter ended December 31, 2016, Callon reported total revenues
of $69.1 million and total revenues
including cash-settled derivatives ("Adjusted Total Revenue," a
non-GAAP financial measure(i)) of $71.2 million, including the $2.1 million impact of settled derivative
contracts. The table above reconciles to the related GAAP measure
of the Company's revenue to Adjusted Total Revenue. Average daily
production for the quarter was 18,359 BOE/d compared to average
daily production of 16,598 BOE/d in the third quarter of 2016.
Average realized prices, including and excluding the effects of
hedging, are detailed below.
Hedging impacts. For the quarter ended December 31, 2016, Callon recognized the
following hedging-related items (in thousands, except per unit
data):
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In
Thousands
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Per
Unit
|
Oil derivatives
contracts
|
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Net gain on
settlements
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$
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2,334
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$
|
1.82
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Net loss on fair
value adjustments
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(10,639)
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Total
net loss on oil derivatives contracts
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|
$
|
(8,305)
|
|
|
|
|
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|
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Natural gas
derivatives contracts
|
|
|
|
|
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Net loss on
settlements
|
|
$
|
(255)
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|
$
|
(0.10)
|
Net loss on fair
value adjustments
|
|
|
(392)
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Total
net loss on natural gas derivatives contracts
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|
$
|
(647)
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|
|
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Total derivatives
contracts
|
|
|
|
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Net gain on
settlements
|
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$
|
2,079
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|
$
|
1.23
|
Net loss on fair
value adjustments
|
|
|
(11,031)
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Total
net loss on total derivatives contracts
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|
$
|
(8,952)
|
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|
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Average realized prices, including and excluding the impact of
cash settled derivatives during the fourth quarter, were as
follows:
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|
|
Three Months
Ended
|
|
|
December 31,
2016
|
Average realized
sales price
|
|
|
|
Oil (per
Bbl) (excluding impact of cash-settled derivatives)
|
|
$
|
47.05
|
Impact of cash-settled
derivatives
|
|
|
1.82
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Oil (per
Bbl) (including impact of cash-settled derivatives)
|
|
$
|
48.87
|
|
|
|
|
Natural
gas (per Mcf) (excluding impact of cash-settled
derivatives)
|
|
$
|
3.53
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Impact of cash-settled
derivatives
|
|
|
(0.10)
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Natural
gas (per Mcf) (including impact of cash-settled
derivatives)
|
|
$
|
3.43
|
|
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Total
(per BOE) (excluding impact of cash-settled derivatives)
|
|
$
|
40.90
|
Impact of cash-settled
derivatives
|
|
|
1.23
|
Total
(per BOE) (including impact of cash-settled derivatives)
|
|
$
|
42.13
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
December 31,
2016
|
|
September 30,
2016
|
|
December 31,
2015
|
Additional per BOE
data
|
|
|
|
|
|
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Sales
price, excluding impact of cash-settled derivatives
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|
$
|
40.90
|
|
$
|
36.63
|
|
$
|
34.42
|
Sales
price, including impact of cash-settled derivatives
|
|
|
42.13
|
|
|
39.30
|
|
|
44.60
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense, including workover and gathering
|
|
$
|
8.36
|
|
$
|
6.52
|
|
$
|
6.47
|
Production taxes
|
|
|
2.20
|
|
|
2.28
|
|
|
2.04
|
Depletion, depreciation and amortization
|
|
|
13.06
|
|
|
11.33
|
|
|
17.29
|
Adjusted
G&A(a)
|
|
|
|
|
|
|
|
|
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Cash
component
|
|
|
2.84
|
|
|
2.38
|
|
|
3.80
|
Non-cash
component
|
|
|
0.54
|
|
|
0.58
|
|
|
0.65
|
|
|
|
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(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.
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(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
December 31, 2016 was $8.36 per BOE, compared to LOE of $6.52 per BOE in the third quarter of 2016. The
increase in this metric was primarily related to an increase in the
number of workover activities in the quarter and higher fuel and
power expenses related to assets acquired during 2016. We continue
to make investments in infrastructure in these new operating 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 $2.20 per BOE in the
fourth 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
December 31, 2016 was $13.06 per BOE compared to $11.33 per BOE in the third 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.
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 $5.7
million, or $3.38 per BOE, for
the fourth quarter of 2016 compared to $4.5
million, or $2.96 per BOE, for
the third quarter of 2016. The cash component of Adjusted G&A
was $4.8 million, or $2.84 per BOE, for the fourth quarter of 2016
compared to $3.6 million, or
$2.38 per BOE, for the third quarter
of 2016.
For the fourth 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):
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|
|
|
|
|
|
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Recurring
|
|
|
|
|
|
|
Cash
|
|
Non-Cash
|
|
|
Total
|
G&A
expenses
|
|
|
|
|
|
|
|
|
|
|
Cash
G&A
|
|
$
|
4,800
|
|
$
|
—
|
|
|
$
|
4,800
|
Restricted stock share-based compensation
|
|
|
—
|
|
|
801
|
|
|
|
801
|
Change
in the fair value of liability share-based awards
|
|
|
—
|
|
|
857
|
|
|
|
857
|
Corporate depreciation & amortization
|
|
|
—
|
|
|
104
|
|
|
|
104
|
Total G&A
expense:
|
|
$
|
4,800
|
|
$
|
1,762
|
|
|
$
|
6,562
|
Adjusted
G&A
|
|
|
|
|
|
|
|
|
|
|
Less:
Change in the fair value of liability share-based awards
|
|
|
|
|
|
|
|
|
$
|
(857)
|
Adjusted G&A –
total
|
|
|
|
|
|
|
|
|
|
5,705
|
Restricted stock share-based compensation (non-cash)
|
|
|
|
|
|
|
|
|
|
(801)
|
Corporate depreciation & amortization (non-cash)
|
|
|
|
|
|
|
|
|
|
(104)
|
Adjusted G&A –
cash component
|
|
|
|
|
|
|
|
|
$
|
4,800
|
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 benefit of less than $0.1 million for the three months ended
December 31, 2016. At December 31, 2016 we had a valuation allowance of
$140.2 million. Adjusted Income per
fully diluted common share, a non-GAAP financial
measure(i), adjusts our income (loss) available to
common stockholders to reflect our theoretical tax provision for
the quarter as if the valuation allowance did not exist.
A breakdown of the Company's actual 2016 capital expenditures
and anticipated 2017 operational plan and associated expenditures
is presented below on an accrual, or GAAP, basis:
|
|
|
|
|
|
|
|
|
2016
Actual
|
|
2017
Forecast
|
Net operated
horizontal well completions
|
|
|
|
|
|
|
Midland
Basin
|
|
|
23.7
|
|
|
30 - 32
|
Delaware
Basin
|
|
|
—
|
|
|
3 - 4
|
|
|
|
|
|
|
|
Average lateral
length
|
|
|
6,510
|
|
|
~7,500
|
Average working
interest
|
|
|
~74%
|
|
|
~75%
|
|
|
|
|
|
|
|
Gross horizontal
well costs ($MM)
|
|
|
|
|
|
|
Midland
Basin (7,500' drilled lateral)
|
|
|
|
|
$
|
5.0 - 5.5
|
Delaware
Basin (10,000' drilled lateral)
|
|
|
|
|
$
|
8.5 - 9.5
|
|
|
|
|
|
|
|
Non-operated
horizontal activity ($MM)
|
|
|
|
|
$
|
7.5 - 10.0
|
|
|
|
|
|
|
|
Capital
expenditures ($MM, accrual basis)
|
|
|
|
|
|
|
Drilling
and completion
|
|
$
|
117.4
|
|
$
|
240 - 255
|
Facilities and other
|
|
|
38.9
|
|
|
85 - 95
|
Total operational
capital expenditures
|
|
$
|
156.3
|
|
$
|
325 - 350
|
Proved Reserves
The Company recently completed the reserve audit for the year
ended December 31, 2016 with its
independent reserve auditor, DeGolyer and MacNaughton. As of
December 31, 2016, Callon's estimated
total proved reserves were 91.6 million BOE, a 69% increase over
the previous year-end. The proved reserves estimate is comprised of
78% oil of which our total proved developed estimated volumes are
comprised of 76% oil. Included in total proved reserve estimates
are 105 (gross) horizontal proved undeveloped locations. These
estimates do not include the impact of our recently completed
acquisition in the Delaware
Basin.
The following table presents the progression of our estimated
net proved oil and natural gas reserves from December 31, 2015 to 2016, and in each case,
prepared in accordance with the rules and regulations of the
SEC.
|
|
|
|
|
|
|
|
|
Oil
|
|
Natural
Gas
|
|
Total
|
Proved developed
and undeveloped reserves
|
|
(MBbls)
|
|
(MMcf)
|
|
(MBOE)
|
As of December 31,
2015
|
|
43,348
|
|
65,537
|
|
54,271
|
Revisions to previous
estimates
|
|
(5,738)
|
|
13,929
|
|
(3,417)
|
Extensions and
discoveries
|
|
14,479
|
|
17,194
|
|
17,345
|
Purchases, net of
sales, of reserves in place
|
|
23,336
|
|
33,709
|
|
28,954
|
Production
|
|
(4,280)
|
|
(7,758)
|
|
(5,573)
|
As of December 31,
2016
|
|
71,145
|
|
122,611
|
|
91,580
|
Callon added a total of 17.3 MMBOE in 2016 from horizontal
development of a portion of our properties, replacing 311% of 2016
production as calculated by the sum of reserve extensions,
discoveries and revisions (including all price-related revisions),
divided by annual production ("Organic reserve replacement"). The
Company's finding and development from extensions and discoveries
"Drill-Bit F&D costs" were $8.77
per BOE calculated as cash costs incurred for exploration and
development divided by the sum of extensions and discoveries. See
"Non-GAAP Financial Measures and Reconciliations" included within
this release for related disclosures and calculations.
2017 Guidance Update
|
|
|
|
|
|
|
First
Quarter
|
|
Annual
|
|
|
2017
|
|
2017
|
Total production
(BOE/d)
|
|
19,500 -
21,000
|
|
22,500 -
25,500
|
%
oil
|
|
75% - 77%
|
|
75% - 77%
|
Income Statement
Expenses (per BOE)
|
|
|
|
|
LOE,
including workovers
|
|
$6.75 -
$7.50
|
|
$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)
|
|
$2.50 -
$3.00
|
|
$2.00 -
$2.50
|
Adjusted
G&A: non-cash component (b)
|
|
$0.75 -
$1.25
|
|
$0.50 -
$1.00
|
Interest
expense (c)
|
|
$0.00 -
$0.00
|
|
$0.00 -
$0.00
|
Effective income tax rate
|
|
0.0%
|
|
0.0%
|
Capital
expenditures ($MM, accrual basis)
|
|
|
|
|
Total
operational capital expenditures (d)
|
|
$70 - $75
|
|
$325 -
$350
|
Capitalized expenses (cash component)
|
|
$10 - $12
|
|
$40 - $45
|
|
|
|
|
(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 fourth 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.
|
(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 as
of February 27, 2017:
|
|
|
|
|
|
|
|
|
For the Full Year
of
|
|
For the Full Year
of
|
Oil
contracts
|
|
2017
|
|
2018
|
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
|
|
$
|
—
|
Deferred premium
put option
|
|
|
|
|
|
|
Total
volume (MBbls)
|
|
|
498
|
|
|
—
|
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)
|
|
|
1,351
|
|
|
—
|
Weighted
average price per Bbl
|
|
|
|
|
|
|
Ceiling (short
call)
|
|
$
|
58.19
|
|
$
|
—
|
Floor (long
put)
|
|
$
|
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 differential)
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
|
2,004
|
|
|
1,825
|
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
|
|
|
|
|
|
|
|
Natural gas
contracts
|
|
|
|
|
|
|
Collar contracts
combined with short puts (Henry Hub, 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
|
|
$
|
—
|
Collar contracts
(Henry Hub, two-way collars)
|
|
|
|
|
|
|
Total
volume (Bbtu)
|
|
|
1,460
|
|
|
—
|
Weighted
average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call
option)
|
|
$
|
3.68
|
|
$
|
—
|
Floor (long put
option)
|
|
$
|
3.00
|
|
$
|
—
|
Income (Loss) Available to Common Shareholders. The
Company reported a net loss available to common shareholders of
$3.6 million in the fourth quarter of
2016 and Adjusted Income available to common shareholders of
$13.1 million, or $0.08 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):
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
Months Ended
|
|
|
December 31,
2016
|
|
September 30,
2016
|
|
December 31,
2015
|
Income (loss)
available to common stockholders
|
|
$
|
(3,570)
|
|
$
|
19,315
|
|
$
|
(115,144)
|
Change
in valuation allowance
|
|
|
559
|
|
|
(7,907)
|
|
|
40,025
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
78,737
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
7,170
|
|
|
(679)
|
|
|
(635)
|
Rig
termination fee
|
|
|
—
|
|
|
—
|
|
|
(368)
|
Change
in the fair value of share-based awards
|
|
|
590
|
|
|
2,192
|
|
|
1,197
|
Loss on
early extinguishment of debt
|
|
|
8,374
|
|
|
—
|
|
|
—
|
Adjusted
Income
|
|
$
|
13,123
|
|
$
|
12,921
|
|
$
|
3,812
|
Adjusted Income per
fully diluted common share
|
|
$
|
0.08
|
|
$
|
0.09
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
Months Ended
|
|
|
December 31,
2016
|
|
September 30,
2016
|
|
December 31,
2015
|
Net income
(loss)
|
|
$
|
(1,746)
|
|
$
|
21,139
|
|
$
|
(113,170)
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
121,134
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
11,030
|
|
|
(1,044)
|
|
|
(977)
|
Change
in the fair value of share-based awards
|
|
|
1,718
|
|
|
4,150
|
|
|
2,354
|
Rig
termination fee
|
|
|
—
|
|
|
—
|
|
|
(566)
|
Loss on
early extinguishment of debt
|
|
|
12,883
|
|
|
—
|
|
|
—
|
Acquisition expense
|
|
|
1,263
|
|
|
456
|
|
|
27
|
Income
tax (benefit) expense
|
|
|
48
|
|
|
(62)
|
|
|
—
|
Interest
expense
|
|
|
1,369
|
|
|
831
|
|
|
5,544
|
Depreciation, depletion and amortization
|
|
|
22,512
|
|
|
17,733
|
|
|
17,308
|
Accretion expense
|
|
|
196
|
|
|
187
|
|
|
175
|
Adjusted
EBITDA
|
|
$
|
49,273
|
|
$
|
43,390
|
|
$
|
31,829
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the fourth quarter of 2016 was
$44.4 million and is reconciled to
operating cash flow in the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
December 31,
2016
|
|
September 30,
2016
|
|
December 31,
2015
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
(1,746)
|
|
$
|
21,139
|
|
$
|
(113,170)
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
22,512
|
|
|
17,733
|
|
|
17,308
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
—
|
|
|
121,134
|
Accretion expense
|
|
|
196
|
|
|
187
|
|
|
175
|
Amortization of non-cash debt related items
|
|
|
744
|
|
|
810
|
|
|
781
|
Deferred
income tax (benefit) expense
|
|
|
48
|
|
|
(62)
|
|
|
—
|
Net
(gain) loss on derivatives, net of settlements
|
|
|
11,030
|
|
|
(1,044)
|
|
|
(977)
|
Loss on
early extinguishment of debt
|
|
|
9,883
|
|
|
—
|
|
|
—
|
Rig
termination fee
|
|
|
—
|
|
|
—
|
|
|
(566)
|
Non-cash
expense related to equity share-based awards
|
|
|
811
|
|
|
608
|
|
|
521
|
Change
in the fair value of liability share-based awards
|
|
|
908
|
|
|
3,371
|
|
|
1,853
|
Discretionary cash
flow
|
|
$
|
44,386
|
|
$
|
42,742
|
|
$
|
27,059
|
|
|
|
|
|
|
|
|
|
|
Changes
in working capital
|
|
|
(7,832)
|
|
|
2,927
|
|
|
4,475
|
Payments
to settle asset retirement obligations
|
|
|
(576)
|
|
|
(576)
|
|
|
(211)
|
Net cash provided by
operating activities
|
|
$
|
35,978
|
|
$
|
45,093
|
|
$
|
31,323
|
F&D and Reserve Replacement:
|
|
|
|
|
|
|
|
|
Calculation
Parameters
|
|
2016
Metrics
|
Production
(MBOE)
|
|
|
(A)
|
|
|
5,573
|
|
|
|
|
|
|
|
Proved Reserve
Data
|
|
|
|
|
|
|
Proved reserves
(MBOE)
|
|
|
|
|
|
|
Total (MBOE)
extensions and discoveries
|
|
|
(B)
|
|
|
17,345
|
PUD
additions
|
|
|
(C)
|
|
|
12,035
|
PUDs transferred to
PDP
|
|
|
(D)
|
|
|
6,823
|
Total annual reserve
additions, net of revisions
|
|
|
(E)
|
|
|
42,882
|
|
|
|
|
|
|
|
Capital Costs (in
thousands)
|
|
|
|
|
|
|
Property acquisition
costs
|
|
|
|
|
|
|
Exploration costs
|
|
|
|
|
$
|
38,612
|
Development costs
|
|
|
|
|
|
151,735
|
Unevaluated
properties
|
|
|
|
|
|
|
Exploration costs
|
|
|
(F)
|
|
|
8,631
|
Transfers to evaluated properties
|
|
|
|
|
|
(40,621)
|
Leasehold and seismic
|
|
|
|
|
|
(6,220)
|
Total capital costs
incurred
|
|
|
(G)
|
|
$
|
152,137
|
|
|
|
|
|
|
|
Drill-Bit F&D
costs per BOE (two-stream)
|
|
|
(G) / (B)
|
|
$
|
8.77
|
PD F&D per BOE
(two-stream)
|
|
|
(G - F) / (B - C +
D)
|
|
$
|
11.83
|
|
|
|
|
|
|
|
Organic reserve
replacement ratio
|
|
|
(B) / (A)
|
|
$
|
311%
|
All-sources reserve
replacement ratio
|
|
|
(E) / (A)
|
|
$
|
769%
|
Callon Petroleum
Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share
data)
|
|
|
|
|
|
|
|
December 31,
2016
|
|
December 31,
2015
|
ASSETS
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
652,993
|
|
$
|
1,224
|
Accounts
receivable
|
|
69,783
|
|
|
39,624
|
Fair value of
derivatives
|
|
103
|
|
|
19,943
|
Other current
assets
|
|
2,247
|
|
|
1,461
|
Total current
assets
|
|
725,126
|
|
|
62,252
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
|
|
Evaluated properties
|
|
2,754,353
|
|
|
2,335,223
|
Less
accumulated depreciation, depletion, amortization and
impairment
|
|
(1,947,673)
|
|
|
(1,756,018)
|
Net
evaluated oil and natural gas properties
|
|
806,680
|
|
|
579,205
|
Unevaluated properties
|
|
668,721
|
|
|
132,181
|
Total oil and natural
gas properties
|
|
1,475,401
|
|
|
711,386
|
Other property and
equipment, net
|
|
14,114
|
|
|
7,700
|
Restricted
investments
|
|
3,332
|
|
|
3,309
|
Deferred financing
costs related to the senior secured revolving credit
facility
|
|
3,092
|
|
|
3,642
|
Acquisition
deposit
|
|
46,138
|
|
|
—
|
Other assets,
net
|
|
384
|
|
|
305
|
Total
assets
|
$
|
2,267,587
|
|
$
|
788,594
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
95,577
|
|
$
|
70,970
|
Accrued
interest
|
|
6,057
|
|
|
5,989
|
Cash-settleable
restricted stock unit awards
|
|
8,919
|
|
|
10,128
|
Asset retirement
obligations
|
|
2,729
|
|
|
790
|
Fair value of
derivatives
|
|
18,268
|
|
|
—
|
Total current
liabilities
|
|
131,550
|
|
|
87,877
|
Senior secured
revolving credit facility
|
|
—
|
|
|
40,000
|
Secured second lien
term loan, net of unamortized deferred financing costs
|
|
—
|
|
|
288,565
|
6.125% senior
unsecured notes due 2024, net of unamortized deferred financing
costs
|
|
390,219
|
|
|
—
|
Asset retirement
obligations
|
|
3,932
|
|
|
4,317
|
Cash-settleable
restricted stock unit awards
|
|
8,071
|
|
|
4,877
|
Deferred tax
liability
|
|
90
|
|
|
—
|
Fair value of
derivatives
|
|
28
|
|
|
—
|
Other long-term
liabilities
|
|
295
|
|
|
200
|
Total
liabilities
|
|
534,185
|
|
|
425,836
|
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 1,578,948
shares outstanding, respectively
|
|
15
|
|
|
16
|
Common stock, $0.01
par value, 300,000,000 and 150,000,000 shares authorized;
201,041,320 and 80,087,148 shares outstanding,
respectively
|
|
2,010
|
|
|
801
|
Capital in excess of
par value
|
|
2,171,514
|
|
|
702,970
|
Accumulated
deficit
|
|
(440,137)
|
|
|
(341,029)
|
Total stockholders'
equity
|
|
1,733,402
|
|
|
362,758
|
Total liabilities and
stockholders' equity
|
$
|
2,267,587
|
|
$
|
788,594
|
Callon Petroleum
Company
Consolidated Statements of Operations
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
sales
|
|
$
|
60,559
|
|
$
|
30,582
|
|
$
|
177,652
|
|
$
|
125,166
|
Natural
gas sales
|
|
|
8,522
|
|
|
2,981
|
|
|
23,199
|
|
|
12,346
|
Total operating
revenues
|
|
|
69,081
|
|
|
33,563
|
|
|
200,851
|
|
|
137,512
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
14,124
|
|
|
6,308
|
|
|
38,353
|
|
|
27,036
|
Production taxes
|
|
|
3,717
|
|
|
1,993
|
|
|
11,870
|
|
|
9,793
|
Depreciation, depletion and amortization
|
|
|
22,051
|
|
|
16,854
|
|
|
71,369
|
|
|
69,249
|
General
and administrative
|
|
|
6,562
|
|
|
6,180
|
|
|
26,317
|
|
|
28,347
|
Accretion expense
|
|
|
196
|
|
|
175
|
|
|
958
|
|
|
660
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
121,134
|
|
|
95,788
|
|
|
208,435
|
Rig
termination fee
|
|
|
—
|
|
|
(566)
|
|
|
—
|
|
|
3,075
|
Acquisition expense
|
|
|
1,263
|
|
|
27
|
|
|
3,673
|
|
|
27
|
Total operating
expenses
|
|
|
47,913
|
|
|
152,105
|
|
|
248,328
|
|
|
346,622
|
Income
(loss) from operations
|
|
|
21,168
|
|
|
(118,542)
|
|
|
(47,477)
|
|
|
(209,110)
|
Other (income)
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net of capitalized amounts
|
|
|
1,369
|
|
|
5,544
|
|
|
11,871
|
|
|
21,111
|
Loss on
early extinguishment of debt
|
|
|
12,883
|
|
|
—
|
|
|
12,883
|
|
|
—
|
(Gain)
loss on derivative contracts
|
|
|
8,952
|
|
|
(10,895)
|
|
|
20,233
|
|
|
(28,358)
|
Other
income
|
|
|
(338)
|
|
|
(21)
|
|
|
(637)
|
|
|
(198)
|
Total other (income)
expense
|
|
|
22,866
|
|
|
(5,372)
|
|
|
44,350
|
|
|
(7,445)
|
Loss
before income taxes
|
|
|
(1,698)
|
|
|
(113,170)
|
|
|
(91,827)
|
|
|
(201,665)
|
Income tax (benefit)
expense
|
|
|
48
|
|
|
—
|
|
|
(14)
|
|
|
38,474
|
Net loss
|
|
|
(1,746)
|
|
|
(113,170)
|
|
|
(91,813)
|
|
|
(240,139)
|
Preferred stock
dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
(7,295)
|
|
|
(7,895)
|
Loss
available to common stockholders
|
|
$
|
(3,570)
|
|
$
|
(115,144)
|
|
$
|
(99,108)
|
|
$
|
(248,034)
|
Loss per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.02)
|
|
$
|
(1.58)
|
|
$
|
(0.78)
|
|
$
|
(3.77)
|
Diluted
|
|
$
|
(0.02)
|
|
$
|
(1.58)
|
|
$
|
(0.78)
|
|
$
|
(3.77)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in
computing loss per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
166,258
|
|
|
73,036
|
|
|
126,258
|
|
|
65,708
|
Diluted
|
|
|
166,258
|
|
|
73,036
|
|
|
126,258
|
|
|
65,708
|
Callon Petroleum
Company
Consolidated Statements of Cash Flows
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
For the Year Ended
December 31,
|
|
|
2016
|
|
2015
|
|
|
2016
|
|
|
2015
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$
|
(1,746)
|
|
$
|
(113,170)
|
|
$
|
(91,813)
|
|
$
|
(240,139)
|
Adjustments to
reconcile net income to cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
22,512
|
|
|
17,308
|
|
|
73,072
|
|
|
69,891
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
121,134
|
|
|
95,788
|
|
|
208,435
|
Accretion expense
|
|
|
196
|
|
|
175
|
|
|
958
|
|
|
660
|
Amortization of non-cash debt related items
|
|
|
744
|
|
|
781
|
|
|
3,115
|
|
|
3,123
|
Deferred
income tax expense
|
|
|
48
|
|
|
—
|
|
|
(14)
|
|
|
38,474
|
Net loss
(gain) on derivatives, net of settlements
|
|
|
11,030
|
|
|
(977)
|
|
|
38,135
|
|
|
6,658
|
Non-cash
loss on early extinguishment of debt
|
|
|
9,883
|
|
|
—
|
|
|
9,883
|
|
|
—
|
Non-cash
expense related to equity share-based awards
|
|
|
811
|
|
|
521
|
|
|
558
|
|
|
221
|
Change
in the fair value of liability share-based awards
|
|
|
908
|
|
|
1,853
|
|
|
6,953
|
|
|
6,612
|
Payments
to settle asset retirement obligations
|
|
|
(576)
|
|
|
(211)
|
|
|
(1,471)
|
|
|
(3,258)
|
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(13,611)
|
|
|
2,517
|
|
|
(30,055)
|
|
|
(4,761)
|
Other current
assets
|
|
|
(535)
|
|
|
(51)
|
|
|
(786)
|
|
|
(20)
|
Current
liabilities
|
|
|
5,473
|
|
|
1,546
|
|
|
25,288
|
|
|
8,001
|
Change in other
long-term liabilities
|
|
|
10
|
|
|
(20)
|
|
|
96
|
|
|
80
|
Change in other
assets, net
|
|
|
831
|
|
|
(83)
|
|
|
(840)
|
|
|
338
|
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
|
|
|
35,978
|
|
|
31,323
|
|
|
118,567
|
|
|
86,852
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(67,334)
|
|
|
(51,593)
|
|
|
(190,032)
|
|
|
(227,292)
|
Acquisitions
|
|
|
(352,622)
|
|
|
(29,396)
|
|
|
(654,679)
|
|
|
(32,245)
|
Acquisition
deposit
|
|
|
(13,438)
|
|
|
—
|
|
|
(46,138)
|
|
|
—
|
Proceeds from sales
of mineral interest and equipment
|
|
|
1,639
|
|
|
29
|
|
|
24,562
|
|
|
377
|
Net cash used in
investing activities
|
|
|
(431,755)
|
|
|
(80,960)
|
|
|
(866,287)
|
|
|
(259,160)
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
|
|
—
|
|
|
51,000
|
|
|
217,000
|
|
|
181,000
|
Payments on senior
secured revolving credit facility
|
|
|
—
|
|
|
(110,000)
|
|
|
(257,000)
|
|
|
(176,000)
|
Payment of deferred
financing costs
|
|
|
(10,153)
|
|
|
—
|
|
|
(10,793)
|
|
|
—
|
Issuance of common
stock
|
|
|
634,862
|
|
|
109,913
|
|
|
1,357,577
|
|
|
175,459
|
Payment of preferred
stock dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
(7,295)
|
|
|
(7,895)
|
Net cash provided
by financing activities
|
|
|
722,885
|
|
|
48,939
|
|
|
1,399,489
|
|
|
172,564
|
Net change in cash
and cash equivalents
|
|
|
327,108
|
|
|
(698)
|
|
|
651,769
|
|
|
256
|
Balance,
beginning of period
|
|
|
325,885
|
|
|
1,922
|
|
|
1,224
|
|
|
968
|
Balance,
end of period
|
|
$
|
652,993
|
|
$
|
1,224
|
|
$
|
652,993
|
|
$
|
1,224
|
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," "Adjusted Total Revenues",
"Drill-Bit F&D costs", "PD F&D costs" and "Organic reserve
replacement." 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.
- We believe "Drill-Bit F&D costs," "PD F&D costs" and
"Organic reserve replacement" ratios are non-GAAP metrics commonly
used by Callon and other companies in our industry, as well as
analysts and investors, to measure and evaluate the cost of
replenishing annual production and adding proved reserves. The
Company's definitions of "Drill-Bit F&D costs," "PD F&D
costs" and "Organic reserve replacement" may differ significantly
from definitions used by other companies to compute similar
measures and as a result may not be comparable to similar measures
provided by other companies. Consequently, we provided the detail
of our calculation within the included tables.
Earnings Call Information
The Company will host a conference call on Tuesday, February 28, 2017, to discuss fourth
quarter 2016 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Tuesday, February 28,
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:
|
1-855-284-3684
|
International:
|
1-412-317-6061
|
Access
code:
|
1632538
|
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-fourth-quarter-2016-results-300414305.html
SOURCE Callon Petroleum Company