NATCHEZ, Miss., Feb. 27, 2018 /PRNewswire/ -- Callon
Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today
reported results of operations for the three months and full-year
ended December 31, 2017.
Presentation slides accompanying this earnings release are
available on the Company's website at www.callon.com located on the
"Presentations" page within the Investors section of the site.
Financial and operational highlights for the fourth quarter of
2017, and other recent data points, include:
- Full-year 2017 production of 22.9 MBOE/d (78% oil), an increase
of 50% over 2016 volumes
- Fourth quarter 2017 production of 26.5 MBOE/d (79% oil), a
sequential quarterly increase of 18%
- Year-end proved reserves of 137.0 MMBOE (78% oil), a
year-over-year increase of 50%
- Organic reserve replacement(i) of 566% of 2017
production at a "Drill-Bit" finding and development cost
concept(i) of $8.21 per
BOE on a two-stream basis
- Reduced lease operating expense to $4.84 per BOE in the fourth quarter of 2017, a
sequential quarterly decrease of 5%, contributing to a total
reduction of 27% since the first quarter of 2017
- Generated a fourth quarter operating margin of $40.51 per BOE
- Currently operating five horizontal rigs and two dedicated
completion crews
Joe Gatto, President and Chief
Executive Officer commented, "Our full year results for 2017
highlight solid execution by our team, resulting in annual
production growth of more than 50% and a greater than 25% reduction
in lease operating expense over the course of the year. Our
operating margins improved 30% over 2016 and our oil content
remained just below 80%, contributing to strong internal cash flow
generation. Importantly, these top tier cash margins, coupled with
drill-bit finding and development cost below $10 per BOE, are a fundamental driver of
corporate level returns that continue to improve in parallel with
our growth in producing assets. We have recently increased our
operating activity to five drilling rigs and plan to remain at this
pace for the balance of 2018 as we incorporate larger pad
development concepts into our program and drive steady improvement
in our net cash flow profile over the course of the year."
Operations Update
At December 31, 2017, we had 232 gross (171.8 net)
horizontal wells producing from eight established flow units in the
Permian Basin. Net daily production for the three months ended
December 31, 2017 grew approximately 44% to 26.5 thousand
barrels of oil equivalent per day (approximately 79% oil) as
compared to the same period of 2016. Full year production for 2017
averaged 22,940 barrels of oil equivalent per day (approximately
78% oil) reflecting growth of 50% over 2016 volumes.
Midland Basin
During the fourth quarter, over 50% of the wells placed on
production were from our WildHorse area with an average completed
lateral length of approximately 7,300 feet. This area continues to
be a key area of production growth for the company and is projected
to comprise in excess of 30% of our total gross drilling activity
in 2018. Completed lateral lengths are projected to average over
8,000 feet and the majority of activity will continue to focus
predominantly on the development of the Wolfcamp A.
In our Monarch area, we placed six wells on production during
the quarter. Activity in this area continues to focus on the Lower
Spraberry which has consistently generated some of the highest
returns in our portfolio. The three-well Kendra pad, with average
completed lateral lengths of approximately 10,350, has produced
over 236,000 BOE (87% oil) over the first 90 days online.
Additionally, we commenced production of our first multi-well pad
that utilized recycled flowback water volumes and plan to increase
recycling activity in Monarch with upcoming wells. Our 2018
activity plan for Monarch will feature two separate "mega-pad"
concepts incorporating simultaneous development of two contiguous
three-well pads. Each pad will be drilled concurrently by dedicated
rigs and all six wells placed on production at the same time. We
expect these larger pads to be placed on production during the
second half of the year.
In Reagan County at the Ranger area, our first Wolfcamp C well,
together with two Lower Wolfcamp B wells, was completed during the
fourth quarter and began flowback in January. The Wolfcamp C well
continues to produce under natural flowing pressure with recent
production rates in excess of 1,000 BOE/d (85% - 90% oil) and is
still in the process of establishing a peak rate. We anticipate
drilling four (gross) additional Wolfcamp C wells in Ranger during
the course of 2018 with an average working interest of
approximately 55%.
Delaware Basin
We recently completed drilling of our first two-well pad in the
area and also added a second rig to our Spur development program in
February. As part of this increased activity, we plan to enhance
our existing saltwater disposal capacity of over 100,000 barrels
per day with the connection to a pipeline system operated by
Goodnight Midstream that will move water disposal volumes outside
of our operating area. In addition, we are in the final stages of
establishing a recycling program in this area and targeting usage
of up to 50% recycled volumes for completion operations by year end
2018. During the fourth quarter, the Saratoga 7LA well came online and has produced
at an average daily rate of approximately 1,015 BOE/d (83% oil)
during its first 56 days of production.
Capital Expenditures
For the three months ended December 31, 2017, we incurred
$115.8 million in accrued operational
capital expenditures (excluding other items) compared to
$113.4 million in the third quarter
of 2017. Total capital expenditures, inclusive of capitalized
expenses, are detailed below on an accrual and cash basis (in
thousands):
|
Three Months Ended
December 31, 2017
|
|
Operational
|
|
|
|
Capitalized
|
|
Capitalized
|
|
Total
Capital
|
|
Capital
|
|
Other
(a)
|
|
Interest
|
|
G&A
|
|
Expenditures
|
Cash basis
(b)
|
$
|
123,664
|
|
$
|
5,006
|
|
$
|
18,848
|
|
$
|
5,103
|
|
$
|
152,621
|
Timing adjustments
(c)
|
(7,910)
|
|
—
|
|
(9,140)
|
|
—
|
|
(17,050)
|
Non-cash
items
|
—
|
|
—
|
|
—
|
|
1,173
|
|
1,173
|
Accrual
(GAAP) basis
|
$
|
115,754
|
|
$
|
5,006
|
|
$
|
9,708
|
|
$
|
6,276
|
|
$
|
136,744
|
|
|
(a)
|
Includes seismic,
land and other items.
|
(b)
|
Cash basis is a
non-GAAP measure that we believe helps users of the financial
information reconcile amounts to the cash flow statement and to
account for timing related operational changes such as our
development pace and rig count.
|
(c)
|
Includes timing
adjustments related to cash disbursements in the current period for
capital expenditures incurred in the prior period.
|
We also divested certain infrastructure during the fourth
quarter for proceeds of just over $20
million. We anticipate Callon will have additional
opportunities to selectively monetize other infrastructure and
facilities investments as we leverage strategic partnerships and
increasingly transition to the use of recycled water volumes in our
completion operations.
Operating and Financial Results
The following table presents summary information for the periods
indicated:
|
Three Months
Ended
|
|
December 31,
2017
|
|
September 30,
2017
|
|
December 31,
2016
|
Net
production
|
|
|
|
|
|
Oil
(MBbls)
|
1,936
|
|
|
1,591
|
|
|
1,287
|
|
Natural gas
(MMcf)
|
3,018
|
|
|
2,900
|
|
|
2,412
|
|
Total
(MBOE)
|
2,439
|
|
|
2,074
|
|
|
1,689
|
|
Average daily
production (BOE/d)
|
26,511
|
|
|
22,543
|
|
|
18,359
|
|
% oil
(BOE basis)
|
79
|
%
|
|
77
|
%
|
|
76
|
%
|
Oil and natural
gas revenues (in thousands)
|
|
|
|
|
|
Oil
revenue
|
$
|
104,132
|
|
|
$
|
73,349
|
|
|
$
|
60,559
|
|
Natural
gas revenue
|
14,081
|
|
|
11,265
|
|
|
8,522
|
|
Total
|
118,213
|
|
|
84,614
|
|
|
69,081
|
|
Impact
of cash-settled derivatives
|
(4,501)
|
|
|
(1,214)
|
|
|
2,079
|
|
Adjusted Total Revenue
(i)
|
$
|
113,712
|
|
|
$
|
83,400
|
|
|
$
|
71,160
|
|
Average realized
sales price (excluding impact of cash settled
derivatives)
|
|
|
|
|
|
Oil
(Bbl)
|
$
|
53.79
|
|
|
$
|
46.10
|
|
|
$
|
47.05
|
|
Natural
gas (Mcf)
|
4.67
|
|
|
3.88
|
|
|
3.53
|
|
Total
(BOE)
|
48.47
|
|
|
40.80
|
|
|
40.90
|
|
Average realized
sales price (including impact of cash settled
derivatives)
|
|
|
|
|
|
Oil
(Bbl)
|
$
|
51.28
|
|
|
$
|
45.24
|
|
|
$
|
48.87
|
|
Natural
gas (Mcf)
|
4.78
|
|
|
3.94
|
|
|
3.43
|
|
Total
(BOE)
|
46.62
|
|
|
40.21
|
|
|
42.13
|
|
Additional per BOE
data
|
|
|
|
|
|
Sales
price (a)
|
$
|
48.47
|
|
|
$
|
40.80
|
|
|
$
|
40.90
|
|
Lease operating
expense (b)
|
4.84
|
|
|
5.08
|
|
|
7.96
|
|
Gathering and treating
expense
|
0.57
|
|
|
0.52
|
|
|
0.40
|
|
Production
taxes
|
2.55
|
|
|
2.62
|
|
|
2.20
|
|
Operating margin
|
$
|
40.51
|
|
|
$
|
32.58
|
|
|
$
|
30.34
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
$
|
14.98
|
|
|
$
|
13.75
|
|
|
$
|
13.06
|
|
Adjusted
G&A (c)
|
|
|
|
|
|
Cash component
(d)
|
$
|
2.46
|
|
|
$
|
2.50
|
|
|
$
|
2.84
|
|
Non-cash
component
|
0.54
|
|
|
0.65
|
|
|
0.54
|
|
|
|
(a)
|
Excludes the impact
of cash settled derivatives.
|
(b)
|
Excludes gathering
and treating expense.
|
(c)
|
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.
|
(d)
|
Excludes the
amortization of equity-settled share-based incentive awards and
corporate depreciation and amortization.
|
Total Revenue. For the quarter ended
December 31, 2017, Callon reported total revenue of
$118.2 million and total revenue
including cash-settled derivatives ("Adjusted Total Revenue," a
non-GAAP financial measure(i)) of $113.7 million, including the impact of a
$4.5 million loss from the settlement
of derivative contracts. The table above reconciles Adjusted Total
Revenue to the related GAAP measure of the Company's revenue.
Average daily production for the quarter was 26.5 MBOE/d compared
to average daily production of 22.5 MBOE/d in the third quarter of
2017. Average realized prices, including and excluding the effects
of hedging, are detailed below.
Hedging impacts. For the quarter ended December 31,
2017, Callon recognized the following hedging-related items (in
thousands, except per unit data):
|
|
Three Months Ended
December 31, 2017
|
|
|
In
Thousands
|
|
Per
Unit
|
Oil
derivatives
|
|
|
|
|
Net loss on
settlements
|
|
$
|
(4,854)
|
|
|
$
|
(2.51)
|
|
Net loss on fair
value adjustments
|
|
(26,010)
|
|
|
|
Total
loss on oil derivatives
|
|
$
|
(30,864)
|
|
|
|
Natural gas
derivatives
|
|
|
|
|
Net gain on
settlements
|
|
$
|
353
|
|
|
$
|
0.11
|
|
Net loss on fair
value adjustments
|
|
(26)
|
|
|
|
Total
gain on natural gas derivatives
|
|
$
|
327
|
|
|
|
Total oil &
natural gas derivatives
|
|
|
|
|
Net loss on
settlements
|
|
$
|
(4,501)
|
|
|
$
|
(1.85)
|
|
Net loss on fair
value adjustments
|
|
(26,036)
|
|
|
|
Total
loss on total oil & natural gas derivatives
|
|
$
|
(30,537)
|
|
|
|
Lease Operating Expenses, including workover and gathering
expense ("LOE"). LOE per BOE for the three months ended
December 31, 2017 was $5.41 per
BOE, compared to LOE of $5.60 per BOE
in the third quarter of 2017. The decrease in this metric resulted
primarily from an increase in production period over period.
Production Taxes, including ad valorem taxes. Production
taxes were $2.55 per BOE for the
three months ended December 31, 2017, representing
approximately 5.3% of total revenue before the impact of derivative
settlements.
Depreciation, Depletion and Amortization
("DD&A"). DD&A for the three months ended
December 31, 2017 was $14.98 per
BOE compared to $13.75 per BOE in the
third quarter of 2017. The increase on a per unit basis was
primarily attributable to greater increases in our depreciable
asset base and assumed future development costs related to
undeveloped proved reserves as compared to the estimated total
proved reserve base.
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 $7.3
million, or $3.00 per BOE, for
the three months ended December 31, 2017 compared to
$6.5 million, or $3.15 per BOE, for the third quarter of 2017. The
cash component of Adjusted G&A was $6.0
million, or $2.46 per BOE, for
the three months ended December 31, 2017 compared to
$5.2 million, or $2.50 per BOE, for the third quarter of 2017.
For the three months ended December 31, 2017, G&A and
Adjusted G&A, which excludes the amortization of
equity-settled, share-based incentive awards and corporate
depreciation and amortization, are calculated as follows (in
thousands):
|
Three Months
Ended
December 31, 2017
|
Total G&A
expense
|
$
|
8,173
|
|
Less:
Change in the fair value of liability share-based awards
(non-cash)
|
(844)
|
|
Adjusted G&A –
total
|
7,329
|
|
Less:
Restricted stock share-based compensation (non-cash)
|
(1,202)
|
|
Less:
Corporate depreciation & amortization (non-cash)
|
(125)
|
|
Adjusted G&A –
cash component
|
$
|
6,002
|
|
Income tax expense. Callon typically provides for income
taxes at a statutory rate of 35% adjusted for permanent
differences expected to be realized, which primarily relate to
non-deductible executive compensation expenses and state income
taxes. We recorded an income tax expense of $0.2 million for the three months ended
December 31, 2017 which relates to deferred State of Texas gross margin tax. At
December 31, 2017 we had a valuation allowance of $60.9 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 of $8.3
million (or $0.04 per diluted
share) for the quarter as if the valuation allowance did not
exist.
Proved Reserves
The Company recently completed the reserve audit for the year
ended December 31, 2017 with its
independent reserve auditor, DeGolyer and MacNaughton. As of
December 31, 2017, Callon's estimated
total proved reserves were 137.0 MMBOE, a 50% 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 75% oil.
The following table presents the progression of our estimated
net proved oil and natural gas reserves from December 31, 2016 to 2017, and in each case,
prepared in accordance with the rules and regulations of the
SEC.
Proved developed
and undeveloped reserves
|
Oil
(MBbls)
|
|
Natural Gas
(MMcf)
|
|
Total
(MBOE)
|
As of December 31,
2016
|
71,145
|
|
|
122,611
|
|
|
91,580
|
|
Revisions to previous estimates
|
(5,171)
|
|
|
6,336
|
|
|
(4,115)
|
|
Extensions and discoveries
|
39,267
|
|
|
48,648
|
|
|
47,375
|
|
Purchases, net of sales, of reserves in place
|
8,388
|
|
|
12,711
|
|
|
10,507
|
|
Production
|
(6,557)
|
|
|
(10,896)
|
|
|
(8,373)
|
|
As of December 31,
2017
|
107,072
|
|
|
179,410
|
|
|
136,974
|
|
Callon added a total of 47.4 MMBOE in 2017 from horizontal
development of our properties, replacing 566% of 2017 production as
calculated by the sum of reserve extensions and discoveries,
divided by annual production ("Organic reserve replacement"). The
Company's finding and development costs from extensions and
discoveries ("Drill-Bit F&D costs") were $8.21 per BOE calculated as accrual costs
incurred for exploration and development divided by the reserves
(in barrels of oil equivalent) added from extensions and
discoveries. See "Non-GAAP Financial Measures and Reconciliations"
included within this release for related disclosures and
calculations.
Guidance Update
As a result of the Tax Cuts and Jobs Act, signed into law in
December 2017 and effective
January 1, 2018, the new federal
statutory income tax rate was reduced to 21% from 35%. In addition,
the Company adopted the Revenue from Contracts with
Customers accounting standard on January
1, 2018. Starting with the first quarter of 2018, certain
natural gas gathering and treating expenses will be accounted for
as a reduction to revenue.
|
|
2017
Actual
|
|
2018
Forecast
|
Total production
(MBOE/d)
|
|
22.9
|
|
29.5 -
32.0
|
% oil
|
|
78%
|
|
77%
|
Income statement
expenses (per BOE)
|
|
|
|
|
LOE, including
workovers
|
|
$5.46
|
|
$5.25 -
$6.25
|
Production taxes,
including ad valorem (% unhedged revenue)
|
|
6%
|
|
6%
|
Adjusted
G&A: cash component (a)
|
|
$2.51
|
|
$1.75 -
$2.50
|
Adjusted
G&A: non-cash component (b)
|
|
$0.57
|
|
$0.50 -
$1.00
|
Interest
expense (c)
|
|
$0.00
|
|
$0.00
|
Statutory income tax
rate
|
|
36%
|
|
22%
|
Capital
expenditures ($MM, accrual basis)
|
|
|
|
|
Operational (net of
monetizations) (d)
|
|
$389
|
|
$500 -
$540
|
Capitalized
expenses
|
|
$48
|
|
$60 - $70
|
Net operated
horizontal wells placed on production
|
|
37
|
|
43 - 46
|
|
|
(a)
|
Excludes stock-based
compensation and corporate depreciation and
amortization.
|
(b)
|
Excludes certain
non-recurring expenses and non-cash valuation
adjustments.
|
(c)
|
All interest expense
anticipated to be capitalized.
|
(d)
|
Includes seismic,
land and other items. Excludes capitalized expenses.
|
Hedge Portfolio Summary
The following tables summarize our open derivative positions for
the periods indicated:
|
For the Full Year
of
|
|
For the Full Year
of
|
Oil contracts
(WTI)
|
2018
|
|
2019
|
Swap
contracts
|
|
|
|
Total volume
(MBbls)
|
2,009
|
|
|
—
|
|
Weighted average
price per Bbl
|
$
|
51.78
|
|
|
$
|
—
|
|
Collar contracts
(two-way collars)
|
|
|
|
Total volume
(MBbls)
|
365
|
|
|
—
|
|
Weighted average
price per Bbl
|
|
|
|
Ceiling (short
call)
|
$
|
60.50
|
|
|
$
|
—
|
|
Floor (long
put)
|
$
|
50.00
|
|
|
$
|
—
|
|
Collar contracts
combined with short puts (three-way collars)
|
|
|
|
Total volume
(MBbls)
|
3,468
|
|
|
1,825
|
|
Weighted average
price per Bbl
|
|
|
|
Ceiling (short call
option)
|
$
|
60.86
|
|
|
$
|
62.40
|
|
Floor (long put
option)
|
$
|
48.95
|
|
|
$
|
53.00
|
|
Short put
option
|
$
|
39.21
|
|
|
$
|
43.00
|
|
|
|
|
|
|
For the Full Year
of
|
|
For the Full Year
of
|
Oil contracts
(Midland basis differential)
|
2018
|
|
2019
|
Swap
contracts
|
|
|
|
Volume
(MBbls)
|
5,289
|
|
|
—
|
|
Weighted average
price per Bbl
|
$
|
(0.86)
|
|
|
$
|
—
|
|
|
|
|
|
|
For the Full Year
of
|
|
For the Full Year
of
|
Natural gas
contracts
|
2018
|
|
2019
|
Collar contracts
(Henry Hub, two-way collars)
|
|
|
|
Total volume
(BBtu)
|
720
|
|
|
—
|
|
Weighted average
price per MMBtu
|
|
|
|
Ceiling (short call
option)
|
$
|
3.84
|
|
|
$
|
—
|
|
Floor (long put
option)
|
$
|
3.40
|
|
|
$
|
—
|
|
Swap contracts (Henry
Hub)
|
|
|
|
Total volume
(BBtu)
|
3,366
|
|
|
—
|
|
Weighted average price
per MMBtu
|
$
|
2.95
|
|
|
$
|
—
|
|
Income (Loss) Available to Common Shareholders. The
Company reported net income available to common shareholders of
$21.0 million for the three months
ended December 31, 2017 and Adjusted Income available to
common shareholders of $30.2 million,
or $0.15 per diluted share. Adjusted
Income per fully diluted common share, a non-GAAP financial
measure(i), adjusts our income (loss) available to
common stockholders to reflect our theoretical tax provision for
the quarter as if the valuation allowance did not exist. The
following tables reconcile to the related GAAP measure the
Company's income (loss) available to common stockholders to
Adjusted Income and the Company's net income (loss) to Adjusted
EBITDA (in thousands):
|
Three Months
Ended
|
|
December 31,
2017
|
|
September 30,
2017
|
|
December 31,
2016
|
Income (loss)
available to common stockholders
|
$
|
21,001
|
|
|
$
|
15,257
|
|
|
$
|
(3,570)
|
|
Change
in valuation allowance
|
(8,285)
|
|
|
(6,064)
|
|
|
559
|
|
Net loss
on derivatives, net of settlements
|
16,924
|
|
|
8,416
|
|
|
7,170
|
|
Change
in the fair value of share-based awards
|
562
|
|
|
475
|
|
|
590
|
|
Loss on
early extinguishment of debt
|
—
|
|
|
—
|
|
|
8,374
|
|
Adjusted
Income
|
$
|
30,202
|
|
|
$
|
18,084
|
|
|
$
|
13,123
|
|
Adjusted Income per
fully diluted common share
|
$
|
0.15
|
|
|
$
|
0.09
|
|
|
$
|
0.08
|
|
|
|
|
Three Months
Ended
|
|
December 31,
2017
|
|
September 30,
2017
|
|
December 31,
2016
|
Net income
(loss)
|
$
|
22,824
|
|
|
$
|
17,081
|
|
|
$
|
(1,746)
|
|
Net loss
on derivatives, net of settlements
|
26,037
|
|
|
12,947
|
|
|
11,030
|
|
Non-cash
stock-based compensation expense
|
2,101
|
|
|
1,952
|
|
|
1,718
|
|
Loss on
early extinguishment of debt
|
—
|
|
|
—
|
|
|
12,883
|
|
Acquisition expense
|
(112)
|
|
|
205
|
|
|
1,263
|
|
Income
tax expense
|
248
|
|
|
237
|
|
|
48
|
|
Interest
expense
|
461
|
|
|
444
|
|
|
1,369
|
|
Depreciation, depletion and amortization
|
37,222
|
|
|
29,132
|
|
|
22,512
|
|
Accretion expense
|
154
|
|
|
131
|
|
|
196
|
|
Adjusted
EBITDA
|
$
|
88,935
|
|
|
$
|
62,129
|
|
|
$
|
49,273
|
|
Discretionary Cash Flow. Discretionary cash flow, a
non-GAAP measure(i), for the three months ended
December 31, 2017 was $89.0
million and is reconciled to operating cash flow in the
following table (in thousands):
|
Three Months
Ended
|
|
December 31,
2017
|
|
September 30,
2017
|
|
December 31,
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
Net income
(loss)
|
$
|
22,824
|
|
|
$
|
17,081
|
|
|
$
|
(1,746)
|
|
Adjustments to
reconcile net income (loss) to cash provided by operating
activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
37,222
|
|
|
29,132
|
|
|
22,512
|
|
Accretion expense
|
154
|
|
|
131
|
|
|
196
|
|
Amortization of non-cash debt related items
|
455
|
|
|
441
|
|
|
744
|
|
Deferred
income tax expense
|
247
|
|
|
237
|
|
|
48
|
|
Net loss
on derivatives, net of settlements
|
26,037
|
|
|
12,947
|
|
|
11,030
|
|
Loss on
early extinguishment of debt
|
—
|
|
|
—
|
|
|
9,883
|
|
Non-cash
expense related to equity share-based awards
|
1,240
|
|
|
1,219
|
|
|
811
|
|
Change
in the fair value of liability share-based awards
|
865
|
|
|
732
|
|
|
908
|
|
Discretionary cash
flow
|
$
|
89,044
|
|
|
$
|
61,920
|
|
|
$
|
44,386
|
|
Changes
in working capital
|
(8,642)
|
|
|
(7,777)
|
|
|
$
|
(7,832)
|
|
Payments
to settle asset retirement obligations
|
(216)
|
|
|
(250)
|
|
|
(576)
|
|
Net cash provided by
operating activities
|
$
|
80,186
|
|
|
$
|
53,893
|
|
|
$
|
35,978
|
|
F&D and
Reserve Replacement
|
|
|
|
Calculation
|
|
2017
|
|
|
Parameters
|
|
Metrics
|
Production
(MBOE)
|
|
(A)
|
|
8,373
|
|
|
|
|
|
|
Proved reserve
data
|
|
|
|
|
Proved reserves
(MBOE)
|
|
|
|
|
Total
(MBOE) extensions and discoveries
|
|
(B)
|
|
47,375
|
|
PUD
additions
|
|
(C)
|
|
24,322
|
|
PUDs transferred to
PDP
|
|
(D)
|
|
8,281
|
|
Total annual reserve
additions, net of revisions
|
|
(E)
|
|
53,767
|
|
|
|
|
|
|
Capital costs (in
thousands)
|
|
|
|
|
Property acquisition
costs
|
|
|
|
|
Exploration costs
|
|
|
|
$
|
239,453
|
|
Development costs
|
|
|
|
279,424
|
|
Unevaluated
properties
|
|
|
|
|
Exploration costs
|
|
(F)
|
|
6,374
|
|
Transfers to evaluated properties
|
|
|
|
(131,170)
|
|
Leasehold and seismic
|
|
|
|
5,006
|
|
Total capital costs
incurred
|
|
(G)
|
|
$
|
389,075
|
|
|
|
|
|
|
Drill-Bit F&D
costs per BOE (two-stream)
|
|
(G) /
(B)
|
|
$
|
8.21
|
|
PD F&D per BOE
(two-stream)
|
|
(G - F) / (B -
C + D)
|
|
$
|
12.21
|
|
|
|
|
|
|
Organic reserve
replacement ratio
|
|
(B) /
(A)
|
|
566
|
%
|
All-sources reserve
replacement ratio
|
|
(E) /
(A)
|
|
642
|
%
|
Callon Petroleum
Company
|
Consolidated
Balance Sheets
|
(in thousands,
except par and per share values and share data)
|
|
|
December 31,
2017
|
|
December 31,
2016
|
ASSETS
|
|
|
|
Current
assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
27,995
|
|
|
$
|
652,993
|
|
Accounts
receivable
|
114,320
|
|
|
69,783
|
|
Fair value of
derivatives
|
406
|
|
|
103
|
|
Other current
assets
|
2,139
|
|
|
2,247
|
|
Total current
assets
|
144,860
|
|
|
725,126
|
|
Oil and natural gas
properties, full cost accounting method:
|
|
|
|
Evaluated
properties
|
3,429,570
|
|
|
2,754,353
|
|
Less accumulated
depreciation, depletion, amortization and impairment
|
(2,084,095)
|
|
|
(1,947,673)
|
|
Net evaluated oil and
natural gas properties
|
1,345,475
|
|
|
806,680
|
|
Unevaluated
properties
|
1,168,016
|
|
|
668,721
|
|
Total oil and natural
gas properties, net
|
2,513,491
|
|
|
1,475,401
|
|
Other property and
equipment, net
|
20,361
|
|
|
14,114
|
|
Restricted
investments
|
3,372
|
|
|
3,332
|
|
Deferred tax
asset
|
52
|
|
|
—
|
|
Deferred financing
costs
|
4,863
|
|
|
3,092
|
|
Acquisition
deposit
|
900
|
|
|
46,138
|
|
Other assets,
net
|
5,397
|
|
|
384
|
|
Total
assets
|
$
|
2,693,296
|
|
|
$
|
2,267,587
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
|
|
|
Current
liabilities:
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
162,878
|
|
|
$
|
95,577
|
|
Accrued
interest
|
9,235
|
|
|
6,057
|
|
Cash-settleable
restricted stock unit awards
|
4,621
|
|
|
8,919
|
|
Asset retirement
obligations
|
1,295
|
|
|
2,729
|
|
Fair value of
derivatives
|
27,744
|
|
|
18,268
|
|
Total current
liabilities
|
205,773
|
|
|
131,550
|
|
Senior secured
revolving credit facility
|
25,000
|
|
|
—
|
|
6.125% senior
unsecured notes due 2024, net of unamortized deferred financing
costs
|
595,196
|
|
|
390,219
|
|
Asset retirement
obligations
|
4,725
|
|
|
3,932
|
|
Cash-settleable
restricted stock unit awards
|
3,490
|
|
|
8,071
|
|
Deferred tax
liability
|
1,457
|
|
|
90
|
|
Fair value of
derivatives
|
1,284
|
|
|
28
|
|
Other long-term
liabilities
|
405
|
|
|
295
|
|
Total
liabilities
|
837,330
|
|
|
534,185
|
|
Commitments and
contingencies
|
|
|
|
Stockholders'
equity:
|
|
|
|
Preferred stock,
series A cumulative, $0.01 par value and $50.00 liquidation
preference, 2,500,000 shares authorized: 1,458,948 shares
outstanding
|
15
|
|
|
15
|
|
Common stock, $0.01
par value, 300,000,000 shares authorized; 201,836,172 and
201,041,320 shares outstanding, respectively
|
2,018
|
|
|
2,010
|
|
Capital in excess of
par value
|
2,181,359
|
|
|
2,171,514
|
|
Accumulated
deficit
|
(327,426)
|
|
|
(440,137)
|
|
Total stockholders'
equity
|
1,855,966
|
|
|
1,733,402
|
|
Total liabilities and
stockholders' equity
|
$
|
2,693,296
|
|
|
$
|
2,267,587
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Operations
|
(in thousands,
except per share data)
|
|
|
Three Months Ended
December 31,
|
|
Twelve Months
Ended December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Operating
revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
104,132
|
|
|
$
|
60,559
|
|
|
$
|
322,374
|
|
|
$
|
177,652
|
|
Natural gas
sales
|
14,082
|
|
|
8,522
|
|
|
44,100
|
|
|
23,199
|
|
Total operating
revenues
|
118,214
|
|
|
69,081
|
|
|
366,474
|
|
|
200,851
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Lease operating
expenses
|
13,201
|
|
|
14,124
|
|
|
49,907
|
|
|
38,353
|
|
Production
taxes
|
6,228
|
|
|
3,717
|
|
|
22,396
|
|
|
11,870
|
|
Depreciation,
depletion and amortization
|
36,543
|
|
|
22,051
|
|
|
115,714
|
|
|
71,369
|
|
General and
administrative
|
8,172
|
|
|
6,562
|
|
|
27,067
|
|
|
26,317
|
|
Settled share-based
awards
|
—
|
|
|
—
|
|
|
6,351
|
|
|
—
|
|
Accretion
expense
|
154
|
|
|
196
|
|
|
677
|
|
|
958
|
|
Write-down of oil and
natural gas properties
|
—
|
|
|
—
|
|
|
—
|
|
|
95,788
|
|
Acquisition
expense
|
(112)
|
|
|
1,263
|
|
|
2,916
|
|
|
3,673
|
|
Total operating
expenses
|
64,186
|
|
|
47,913
|
|
|
225,028
|
|
|
248,328
|
|
Income (loss) from
operations
|
54,028
|
|
|
21,168
|
|
|
141,446
|
|
|
(47,477)
|
|
Other (income)
expenses:
|
|
|
|
|
|
|
|
Interest expense, net
of capitalized amounts
|
461
|
|
|
1,369
|
|
|
2,159
|
|
|
11,871
|
|
Loss on early
extinguishment of debt
|
—
|
|
|
12,883
|
|
|
—
|
|
|
12,883
|
|
Loss on derivative
contracts
|
30,536
|
|
|
8,952
|
|
|
18,901
|
|
|
20,233
|
|
Other
income
|
(41)
|
|
|
(338)
|
|
|
(1,311)
|
|
|
(637)
|
|
Total other (income)
expense
|
30,956
|
|
|
22,866
|
|
|
19,749
|
|
|
44,350
|
|
Income (loss) before
income taxes
|
23,072
|
|
|
(1,698)
|
|
|
121,697
|
|
|
(91,827)
|
|
Income tax (benefit)
expense
|
248
|
|
|
48
|
|
|
1,273
|
|
|
(14)
|
|
Net income
(loss)
|
22,824
|
|
|
(1,746)
|
|
|
120,424
|
|
|
(91,813)
|
|
Preferred stock
dividends
|
(1,823)
|
|
|
(1,824)
|
|
|
(7,295)
|
|
|
(7,295)
|
|
Income (loss)
available to common stockholders
|
$
|
21,001
|
|
|
$
|
(3,570)
|
|
|
$
|
113,129
|
|
|
$
|
(99,108)
|
|
Income (loss) per
common share:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.10
|
|
|
$
|
(0.02)
|
|
|
$
|
0.56
|
|
|
$
|
(0.78)
|
|
Diluted
|
$
|
0.10
|
|
|
$
|
(0.02)
|
|
|
$
|
0.56
|
|
|
$
|
(0.78)
|
|
Shares used in
computing income (loss) per common share:
|
|
|
|
|
|
|
|
Basic
|
201,835
|
|
|
166,258
|
|
|
201,526
|
|
|
126,258
|
|
Diluted
|
202,426
|
|
|
166,258
|
|
|
202,102
|
|
|
126,258
|
|
Callon Petroleum
Company
|
Consolidated
Statements of Cash Flows
|
(in
thousands)
|
|
|
Three Months Ended
December 31,
|
|
Twelve Months
Ended December 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
22,824
|
|
|
$
|
(1,746)
|
|
|
$
|
120,424
|
|
|
$
|
(91,813)
|
|
Adjustments to
reconcile net income to cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
37,222
|
|
|
22,512
|
|
|
118,051
|
|
|
73,072
|
|
Write-down of
oil and natural gas properties
|
—
|
|
|
—
|
|
|
—
|
|
|
95,788
|
|
Accretion
expense
|
154
|
|
|
196
|
|
|
677
|
|
|
958
|
|
Amortization
of non-cash debt related items
|
455
|
|
|
744
|
|
|
2,150
|
|
|
3,115
|
|
Deferred
income tax (benefit) expense
|
247
|
|
|
48
|
|
|
1,273
|
|
|
(14)
|
|
Loss on
derivatives, net of settlements
|
26,037
|
|
|
11,030
|
|
|
10,429
|
|
|
38,135
|
|
Loss on sale
of other property and equipment
|
—
|
|
|
—
|
|
|
62
|
|
|
—
|
|
Non-cash loss
on early extinguishment of debt
|
—
|
|
|
9,883
|
|
|
—
|
|
|
9,883
|
|
Non-cash
expense related to equity share-based awards
|
1,240
|
|
|
811
|
|
|
8,254
|
|
|
2,765
|
|
Change in the
fair value of liability share-based awards
|
865
|
|
|
908
|
|
|
3,288
|
|
|
6,953
|
|
Payments to
settle asset retirement obligations
|
(216)
|
|
|
(576)
|
|
|
(2,047)
|
|
|
(1,471)
|
|
Changes in
current assets and liabilities:
|
|
|
|
|
|
|
|
Accounts receivable
|
(32,347)
|
|
|
(13,611)
|
|
|
(44,495)
|
|
|
(30,055)
|
|
Other current assets
|
444
|
|
|
(535)
|
|
|
108
|
|
|
(786)
|
|
Current liabilities
|
23,413
|
|
|
5,473
|
|
|
30,947
|
|
|
25,288
|
|
Other long-term liabilities
|
—
|
|
|
10
|
|
|
121
|
|
|
96
|
|
Long-term prepaid
|
—
|
|
|
—
|
|
|
(4,650)
|
|
|
—
|
|
Other assets, net
|
(152)
|
|
|
831
|
|
|
(1,528)
|
|
|
(840)
|
|
Payments for
cash-settled restricted stock unit awards
|
—
|
|
|
—
|
|
|
(13,173)
|
|
|
(10,300)
|
|
Net cash provided by operating activities
|
80,186
|
|
|
35,978
|
|
|
229,891
|
|
|
120,774
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
(152,621)
|
|
|
(67,334)
|
|
|
(419,839)
|
|
|
(190,032)
|
|
Acquisitions
|
(3,952)
|
|
|
(352,622)
|
|
|
(718,456)
|
|
|
(654,679)
|
|
Acquisition
deposit
|
(900)
|
|
|
(13,438)
|
|
|
45,238
|
|
|
(46,138)
|
|
Proceeds from sales
of mineral interest and equipment
|
20,525
|
|
|
1,639
|
|
|
20,525
|
|
|
24,562
|
|
Net cash used in investing activities
|
(136,948)
|
|
|
(431,755)
|
|
|
(1,072,532)
|
|
|
(866,287)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
Borrowings on senior
secured revolving credit facility
|
25,000
|
|
|
—
|
|
|
25,000
|
|
|
217,000
|
|
Payments on senior
secured revolving credit facility
|
—
|
|
|
—
|
|
|
—
|
|
|
(257,000)
|
|
Payments on term
loans
|
—
|
|
|
(300,000)
|
|
|
—
|
|
|
(300,000)
|
|
Issuance of 6.125%
senior unsecured notes due 2024
|
—
|
|
|
400,000
|
|
|
200,000
|
|
|
400,000
|
|
Premium on the
issuance of 6.125% senior unsecured notes due 2024
|
—
|
|
|
—
|
|
|
8,250
|
|
|
—
|
|
Payment of deferred
financing costs
|
(28)
|
|
|
(10,153)
|
|
|
(7,194)
|
|
|
(10,793)
|
|
Issuance of common
stock
|
—
|
|
|
634,862
|
|
|
—
|
|
|
1,357,577
|
|
Payment of preferred
stock dividends
|
(1,824)
|
|
|
(1,824)
|
|
|
(7,295)
|
|
|
(7,295)
|
|
Tax withholdings
related to restricted stock units
|
—
|
|
|
—
|
|
|
(1,118)
|
|
|
(2,207)
|
|
Net cash provided by financing activities
|
23,148
|
|
|
722,885
|
|
|
217,643
|
|
|
1,397,282
|
|
Net change in cash
and cash equivalents
|
(33,614)
|
|
|
327,108
|
|
|
(624,998)
|
|
|
651,769
|
|
Balance,
beginning of period
|
61,609
|
|
|
325,885
|
|
|
652,993
|
|
|
1,224
|
|
Balance, end
of period
|
$
|
27,995
|
|
|
$
|
652,993
|
|
|
$
|
27,995
|
|
|
$
|
652,993
|
|
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures such as
"Discretionary Cash Flow," "Adjusted G&A," "Adjusted Income,"
"Adjusted EBITDA," "Adjusted Total Revenue," "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 is 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), accretion expense, 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
above. 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 our 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 Revenue
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&A 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 Wednesday, February 28, 2018, to discuss fourth
quarter and full-year 2017 financial and operating results.
Please join Callon Petroleum Company via the Internet for a
webcast of the conference call:
Date/Time:
|
Wednesday, February
28, 2018, at 8:00 a.m. Central Time (9:00 a.m. Eastern
Time)
|
Webcast:
|
Select "IR Calendar"
under the "Investors" section of the Company's website:
www.callon.com.
|
Presentation
Slides:
|
Select
"Presentations" under the "Investors" section of the Company's
website: www.callon.com.
|
Alternatively, you may join by telephone using the following
numbers:
Domestic:
|
1-888-317-6003
|
Canada:
|
1-866-284-3684
|
International:
|
1-412-317-6061
|
Access
code:
|
2180929
|
An archive of the conference call webcast will also be available
at www.callon.com under 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 2018 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.
Contact information:
Mark Brewer
Director of Investor Relations
Callon Petroleum Company
ir@callon.com
1-281-589-5279
_________________________________________
|
i)
|
See "Non-GAAP
Financial Measures and Reconciliations" included within this
release for related disclosures and calculations
|
View original
content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-fourth-quarter-2017-results-300605258.html
SOURCE Callon Petroleum Company