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