Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Gene
ral
The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our
2015
Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our
W
eb
site address is
www.callon.com
. All of our filings with the SEC are available free of charge through our
W
eb
site as soon as reasonably practicable after we file them wit
h, or furnish them to, the SEC. Information on our W
eb
site does not form part of this report on Form 10-Q.
We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Bas
in. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational perfor
mance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry s
hale. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through
working interest acquisitions,
acreage purchases, joint ventures and asset swaps.
Our production was approximately
78%
oil and
22%
natural gas for the
six months ended
June 30, 2
016
. On
June 30, 2016
, our
net
acreage position in the Permian Basin was approximatel
y
33,734
net acres
.
Commodity Prices
The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by
the Organization of Petroleum Exporting Countries
and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
|
·
|
|
our revenues, cash flows and earnings;
|
|
·
|
|
the amount of oil and natural gas that we are economically able to produce;
|
|
·
|
|
our ability to attract capital to finance our operations and cost of the capital;
|
|
·
|
|
the amount we are allowed to borrow under our senior secured revolving credit facility; and
|
|
·
|
|
the value of our oil and natural gas properties.
|
Beginning in the second half of 2014, the NYMEX price for a barrel of oil declined from
$105.37
on June 30, 2014
to
$40.06
o
n
August 1, 2016
. For the three months ended
June 30, 2016
, the average NYMEX price for a barrel of oil was
$45.59
per Bbl compared to
$57.95
per Bbl for the same period of
2015
. The NYMEX price for a barrel of oil ranged from a low of
$35.70
per Bbl to a high of
$51.23
per Bbl for the three months ended
June 30, 2016
.
For the three months ended
June 30, 2016
, the average NYMEX price for natural gas was
$1.95
per MMBtu compared to
$2.64
per MMBtu for the same period in
2015
. The NYMEX price for natural gas ranged from a low of
$1.90
per MMBtu to a high of
$2.92
per MMBtu for the three months ended
June 30, 2016
.
The Company uses the full cost method of accounting for its exploration and development activities. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At
June 30, 2016
, the
realized
prices used in determining the estimated future net cash flows from proved reserves were
$40.62
per barrel of oil and
$2.46
per Mcf of natural gas
(including the value of NGLs in the natural gas stream)
. For the
three and six months
ended
June 30,
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
2016
, the Company recognized a write-down
s
of oil and natural gas properties of
$61
m
illion
and
$95.8
million, respectively,
as a result of the ceiling test limitation. Based on prevailing commodity prices in the current environment, we expect to incur additional ceiling test write-downs in the future. However, we do not expect such prevailing commodity prices to have significant adverse effects on our proved oil and gas reserves. See
Note 2
i
n the Footnotes to the Financial Statements for more inform
ation.
The table below presents
the cumulative
results of the full cost ceiling test
for 2016
as of
June 30, 2016
, along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and
natural gas prices. This sensitivity analysis is as of
June 30, 2016
,
and accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to
June 30, 2016
that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-Month Average Realized Prices
|
|
Excess (Deficit) of
full cost ceiling over net capitalized costs
|
|
(Increase) Decrease in excess of full cost ceiling over net capitalized costs
|
Pricing Scenarios
|
|
Oil ($/Bbl)
|
|
Natural gas ($/Mcf)
|
|
(in thousands)
|
June 30, 2016 Actual
|
|
$
|
40.62
|
|
$
|
2.46
|
|
$
|
(95,788)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas +10%
|
|
$
|
44.69
|
|
$
|
2.70
|
|
$
|
(33,871)
|
|
$
|
61,917
|
Oil and natural gas -10%
|
|
|
36.56
|
|
|
2.21
|
|
|
(157,706)
|
|
|
(61,918)
|
Oil price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil +10%
|
|
$
|
44.69
|
|
$
|
2.46
|
|
$
|
(39,289)
|
|
$
|
56,499
|
Oil -10%
|
|
|
36.56
|
|
|
2.46
|
|
|
(152,287)
|
|
|
(56,499)
|
Natural gas sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas +10%
|
|
$
|
40.62
|
|
$
|
2.70
|
|
$
|
(90,370)
|
|
$
|
5,418
|
Natural gas -10%
|
|
|
40.62
|
|
|
2.21
|
|
|
(101,207)
|
|
|
(5,419)
|
Operational Highlights
Our production
grew
41%
a
nd
44%
for
the three
and six
months ended
June 30, 2016
,
respectively,
compared to the same period
s
of
2015
,
in
creasing to
1,224
MBOE from
866
MBOE
and
2,357
MBOE from
1,637
MBOE
for the comparative three
and six
months period
s, respectively
.
For
the three months ended June
3
0, 2016
,
we drill
ed
6
gross (
3.7
net) horizontal wells
and
completed 5 gross (3.4 net) horizontal wells. For the six months ended June 30, 2016, we drilled 1
1
gross (
8
.0
net) horizontal wells and completed 14 gross (10.5 net) horizontal wells. As of June 30, 2016, we had
6
gross (
4.2
net) horizontal wells awaiting completion
, including 2 gross drilled, uncompleted wells recently acquired
.
As of June 30, 2016,
we had
4
1
3
gross (32
3
.5 net) working interest oil wells, 3 gross (0.1 net) royalty interest oil wells and no natural gas wells.
A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natur
al gas.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of
debt instruments.
During 2016,
we completed two
public
common stock offerings to raise additional capital, and we continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plan in the Permian Basin. As of
June 30, 2016
, there was
a
$40
million
balance outstanding on the Credit Facility, and the
borrowing base was
increased
t
o
$3
85
million on
July 13
, 2016.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
For the
six months ended June 30, 2016
, cash and cash equivalents
de
creased
$1.0
million to
$0.2
million compared to
$1.2
million
at
June 30, 2015
.
Liquidity and cash flow
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
(dollars in millions)
|
|
2016
|
|
2015
|
Net cash provided by operating activities
|
|
$
|
37.5
|
|
$
|
30.0
|
Net cash used in investing activities
|
|
|
(335.7)
|
|
|
(130.5)
|
Net cash provided by financing activities
|
|
|
297.2
|
|
|
101.6
|
Net change in cash
|
|
$
|
(1.0)
|
|
$
|
1.1
|
Operating
activities.
For the
six months ended June 30, 2016
, net cash provided by operating activities was
$37.5
million compared to
net cash provided by operating activities of
$30.0
million for the same period in
2015
. The change was predominantly attributable to the following:
|
·
|
|
A
15% increase in revenue offset by
a loss
on settlement of derivative cont
racts
;
|
|
·
|
|
An increase in payments on cash-settled restricted stock unit (“RSU”) awards;
|
|
·
|
|
A decrease in payments related to nonrecurring early retirement expenses that were incurred in 2015; and
|
|
·
|
|
A change related to the timing of working capital payments and receipts.
|
Production, realized prices, and operating expenses are discussed below in Results of Operations. See
Notes 6
and
7
in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Investing activities.
For the
six months ended June 30, 2016
, net cash used in investing activities was
$335.7
million compared to
$130.5
million for the same period in
2015
. The
$205.2
million
in
crease in cash used in investing activities was primarily attributable to the following:
|
·
|
|
A
$54.9
million decrease in operational expenditures due to the transition from a two-rig to a one-rig program in January 2016,
offset in part by
the release of a vertical rig in April 2015; and
|
|
·
|
|
A
$258.9
million increase driven
by various acquisitions, net of proceeds from the sale of mineral interest and equipment, during the
six months ended
months June 30, 2016. The acquisitions were funded with cash and common stock.
|
See
Note 3
in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.
Our investing activities, on a cash basis, include the following for the periods indicated (in millio
ns):
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
2016
|
|
2015
|
|
|
$ Change
|
Operational expenditures
|
|
$
|
63.1
|
|
$
|
118.0
|
|
$
|
(54.9)
|
Capitalized general and administrative costs allocated directly to
|
|
|
|
|
|
|
|
|
|
exploration and development projects
|
|
|
6.2
|
|
|
5.3
|
|
|
0.9
|
Capitalized interest
|
|
|
6.0
|
|
|
5.7
|
|
|
0.3
|
Total capital expenditures (a)
|
|
|
75.3
|
|
|
129.0
|
|
|
(53.7)
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
284.0
|
|
|
1.8
|
|
|
282.2
|
Proceeds from the sale of mineral interest and equipment
|
|
|
(23.6)
|
|
|
(0.3)
|
|
|
(23.3)
|
Total investing activities
|
|
$
|
335.7
|
|
$
|
130.5
|
|
$
|
205.2
|
|
(a)
|
|
On an accrual (GAAP) basis, which is the metho
dology used for establishing our annual capital budget, operational expenditures for the
six
months ended
June 30, 2016
were
$56.2
million. Inclusive of
capitalized general and administrative and interest costs, total
capital
expenditures were
$71.1
million.
|
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See
Note 3
in the Footnotes to the Financial Statements for additional information on acquisitions.
Financing activities.
We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings.
For the
six months ended June 30, 2016
, net cash provided by financing activities was
$297.2
million compared to cash provided by financing activities of
$101.6
million during the same period of
2015
.
The change in net cash provided by financing activities was primarily attributable to the following:
|
·
|
|
Payments, net of borrowings, on our Credit Facility
netted to zero
,
$40
million less than the same period of 2015; and
|
|
·
|
|
A
$235.3
million increase in proceeds resulting from common stock offering
s
in March
and April
2016 as compared to proceeds resulting from
a
common stock offering in March 2015.
|
See
Notes 5 and 10 i
n the Footnotes to the Financial Statements for additional information on our
debt and
equity offerings.
Operational Capital Budget and
Second
Quarter Summary
Subsequent to the acquisitions made during th
e second quarter 2016 (see Note
3 in the Footnotes to the Financial Statements), our operational capital guidance was updated from $75 to $80 million to $95 to $105 million, which reflec
ts an increase in expenditures related to incremental completions and infrastructure investments for future development of the acquired properties.
In early
August
201
6, we
a
nnounced an increase of
our op
erational capital guidance to
$
14
0
million. The i
ncreased guidance reflects expenditures related to the
r
e
activation
of
our idled
second
drilling
rig
that will be
primarily in the WildHorse operating area
,
and increased infrastructure investments to accommodate
development in this area
.
Operational capital expenditures on an accrual basis were
$21.3
mi
llion for the
six
months ended
June 30, 2016
.
In addition to the operational capital expenditures,
$
14.9
million of capitalized general and administrative
and capitalized interest
expenses were accrued in the
six
months ended
June 30, 2016
.
Based upon current commodity price expectations for 2016, we believe that our cash flow from operations and available borrowings under our Credit Facility will be sufficient to fund our remaining 2016 capital program, including working capital require
ments.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Results
of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
% Change
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
948
|
|
|
685
|
|
|
263
|
|
38%
|
Natural gas (MMcf)
|
|
|
1,658
|
|
|
1,084
|
|
|
574
|
|
53%
|
Total (MBOE)
|
|
|
1,224
|
|
|
866
|
|
|
358
|
|
41%
|
Average daily production (BOE/d)
|
|
|
13,451
|
|
|
9,516
|
|
|
3,935
|
|
41%
|
% oil (BOE basis)
|
|
|
77%
|
|
|
79%
|
|
|
|
|
|
Average realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
42.78
|
|
$
|
52.69
|
|
$
|
(9.91)
|
|
(19)%
|
Oil (Bbl) (including impact of cash settled derivatives)
|
|
|
46.69
|
|
|
59.28
|
|
|
(12.59)
|
|
(21)%
|
Natural gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
2.77
|
|
$
|
2.90
|
|
$
|
(0.13)
|
|
(4)%
|
Natural gas (Mcf) (including impact of cash settled derivatives)
|
|
|
2.96
|
|
|
3.32
|
|
|
(0.36)
|
|
(11)%
|
Total (BOE) (excluding impact of cash settled derivatives)
|
|
$
|
36.88
|
|
$
|
45.31
|
|
$
|
(8.43)
|
|
(19)%
|
Total (BOE) (including impact of cash settled derivatives)
|
|
|
40.17
|
|
|
51.05
|
|
|
(10.88)
|
|
(21)%
|
Oil and natural gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
40,555
|
|
$
|
36,093
|
|
$
|
4,462
|
|
12%
|
Natural gas revenue
|
|
|
4,590
|
|
|
3,149
|
|
|
1,441
|
|
46%
|
Total
|
|
$
|
45,145
|
|
$
|
39,242
|
|
$
|
5,903
|
|
15%
|
Additional per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
Sales price (excluding impact of cash settled derivatives)
|
|
$
|
36.88
|
|
$
|
45.31
|
|
$
|
(8.43)
|
|
(19)%
|
Lease operating expense
|
|
|
5.97
|
|
|
7.59
|
|
|
(1.62)
|
|
(21)%
|
Production taxes
|
|
|
2.01
|
|
|
3.41
|
|
|
(1.40)
|
|
(41)%
|
Operating margin
|
|
$
|
28.90
|
|
$
|
34.31
|
|
$
|
(5.41)
|
|
(16)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
% Change
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,840
|
|
|
1,323
|
|
|
517
|
|
39%
|
Natural gas (MMcf)
|
|
|
3,101
|
|
|
1,885
|
|
|
1,216
|
|
65%
|
Total (MBOE)
|
|
|
2,357
|
|
|
1,637
|
|
|
720
|
|
44%
|
Average daily production (BOE/d)
|
|
|
12,951
|
|
|
9,044
|
|
|
3,907
|
|
43%
|
% oil (BOE basis)
|
|
|
78%
|
|
|
81%
|
|
|
|
|
|
Average realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
36.96
|
|
$
|
48.38
|
|
$
|
(11.42)
|
|
(24)%
|
Oil (Bbl) (including impact of cash settled derivatives)
|
|
|
43.05
|
|
|
59.31
|
|
|
(16.26)
|
|
(27)%
|
Natural gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
2.53
|
|
$
|
2.99
|
|
$
|
(0.46)
|
|
(15)%
|
Natural gas (Mcf) (including impact of cash settled derivatives)
|
|
|
2.70
|
|
|
3.44
|
|
|
(0.74)
|
|
(22)%
|
Total (BOE) (excluding impact of cash settled derivatives)
|
|
$
|
32.18
|
|
$
|
42.54
|
|
$
|
(10.36)
|
|
(24)%
|
Total (BOE) (including impact of cash settled derivatives)
|
|
|
37.16
|
|
|
51.89
|
|
|
(14.73)
|
|
(28)%
|
Oil and natural gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
67,998
|
|
$
|
64,002
|
|
$
|
3,996
|
|
6%
|
Natural gas revenue
|
|
|
7,845
|
|
|
5,631
|
|
|
2,214
|
|
39%
|
Total
|
|
$
|
75,843
|
|
$
|
69,633
|
|
$
|
6,210
|
|
9%
|
Additional per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
Sales price (excluding impact of cash settled derivatives)
|
|
$
|
32.18
|
|
$
|
42.54
|
|
$
|
(10.36)
|
|
(24)%
|
Lease operating expense
|
|
|
6.05
|
|
|
8.27
|
|
|
(2.22)
|
|
(27)%
|
Production taxes
|
|
|
1.98
|
|
|
3.19
|
|
|
(1.21)
|
|
(38)%
|
Operating margin
|
|
$
|
24.15
|
|
$
|
31.08
|
|
$
|
(6.93)
|
|
(22)%
|
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Revenues
The following table
is
intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and the underlying commodity prices.
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oil
|
|
Natural Gas
|
|
Total
|
Revenues for the three months ended June 30, 2015
|
|
$
|
36,093
|
|
$
|
3,149
|
|
$
|
39,242
|
Volume increase
|
|
|
13,818
|
|
|
1,670
|
|
|
15,488
|
Price decrease
|
|
|
(9,356)
|
|
|
(229)
|
|
|
(9,585)
|
Net increase
|
|
|
4,462
|
|
|
1,441
|
|
|
5,903
|
Revenues for the three months ended June 30, 2016
|
|
$
|
40,555
|
|
$
|
4,590
|
|
$
|
45,145
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oil
|
|
Natural Gas
|
|
Total
|
Revenues for the six months ended June 30, 2015
|
|
$
|
64,002
|
|
$
|
5,631
|
|
$
|
69,633
|
Volume increase
|
|
|
24,985
|
|
|
3,631
|
|
|
28,616
|
Price decrease
|
|
|
(20,989)
|
|
|
(1,417)
|
|
|
(22,406)
|
Net increase
|
|
|
3,996
|
|
|
2,214
|
|
|
6,210
|
Revenues for the six months ended June 30, 2016
|
|
$
|
67,998
|
|
$
|
7,845
|
|
$
|
75,843
|
Oil revenue
For the quarter ended
June 30, 2016
, oil revenues of
$40.6
million
in
creased
$4.5
million, or
12%
, compared to revenues of
$36.1
million for the same period of
2015
.
T
he
in
crease
in oil revenue was
primarily attributable to a
38%
in
crease in production
offset by a
19%
decrease in the average realized sales price
, which fell to
$42.78
per Bbl from
$52.69
per Bbl
. The
in
crease in production was primarily attributable t
o an increased number of producing wells from
our horizontal drilling program and
acquisitions
,
offset by
normal and expected declines from
our existing wells.
For the
six months ended
June 30, 2016
, oil revenues of
$68.0
million
in
creased
$4.0
million, or
6%
, compared to revenues of
$64.0
million for the same period of
2015
. The
in
crease in oil revenue was primarily attributable to
a
39% i
ncrease in production, and was predominantly offset by
a
24%
decrease in the average realized sales price, which fell to
$36.96
per Bbl from
$48.38
per Bbl. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions, offset by normal and expected declines from our existing wells.
Natural
gas revenue (including NGLs)
Natural gas revenues of
$4.6
million
in
creased
$1.4
million, or
46%
, during the
three months ended
June 30, 2016
,
compared to
$3.1
million for the same period of
2015
. The
in
crease primarily relates to
a
53%
increase in natural gas volume
s
and
was predominantly offset by
a
4%
de
crease in the average price realized, which
fell
to
$2.77
per Mcf from
$2.90
per Mcf, reflecting
de
creases in both natural gas and natural gas liquids prices
.
The
in
crease in
natural gas
production was primarily attributable
to
an
increased number of producing wells
as
mentioned above
, offset by normal and expected declines from our existing wells
.
Natural gas revenues of
$7.8
million increased
$2.2
million, or
39%
, during the
six months ended
,
June 30, 2016
,
compared to
$5.6
million for the same period of
2015
. The increase primarily relates to a
65%
increase in natural gas volumes and was predominantly offset by a
n
15%
decrease in the average price realized, which fell to
$2.53
per Mcf from
$2.99
per Mcf, reflecting decreases in both natural gas and natural gas liquids prices. The increase in natural gas production was primarily attributable to an increased number of producing wells as mentioned above
, offset by normal and expected declines from our existin
g wells
.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Three Months Ended June 30,
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
|
|
2016
|
|
BOE
|
|
2015
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
7,311
|
|
$
|
5.97
|
|
$
|
6,575
|
|
$
|
7.59
|
|
$
|
736
|
|
11%
|
|
$
|
(1.62)
|
|
(21)%
|
Production taxes
|
|
|
2,455
|
|
|
2.01
|
|
|
2,952
|
|
|
3.41
|
|
|
(497)
|
|
(17)%
|
|
|
(1.40)
|
|
(41)%
|
Depreciation, depletion and amortization
|
|
|
16,293
|
|
|
13.31
|
|
|
17,587
|
|
|
20.31
|
|
|
(1,294)
|
|
(7)%
|
|
|
(7.00)
|
|
(34)%
|
General and administrative
|
|
|
6,302
|
|
|
5.15
|
|
|
5,763
|
|
|
6.65
|
|
|
539
|
|
9%
|
|
|
(1.50)
|
|
(23)%
|
Accretion expense
|
|
|
395
|
|
|
0.32
|
|
|
134
|
|
|
0.15
|
|
|
261
|
|
195%
|
|
|
0.17
|
|
113%
|
Acquisition expense
|
|
|
1,906
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
|
1,906
|
|
nm
|
|
|
nm
|
|
nm
|
Write-down of oil and natural gas properties
|
|
|
61,012
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
|
61,012
|
|
nm
|
|
|
nm
|
|
nm
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
|
|
2016
|
|
BOE
|
|
2015
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
14,268
|
|
$
|
6.05
|
|
$
|
13,534
|
|
$
|
8.27
|
|
$
|
734
|
|
5%
|
|
$
|
(2.22)
|
|
(27)%
|
Production taxes
|
|
|
4,675
|
|
|
1.98
|
|
|
5,217
|
|
|
3.19
|
|
|
(542)
|
|
(10)%
|
|
|
(1.21)
|
|
(38)%
|
Depreciation, depletion and amortization
|
|
|
32,015
|
|
|
13.58
|
|
|
35,691
|
|
|
21.80
|
|
|
(3,676)
|
|
(10)%
|
|
|
(8.22)
|
|
(38)%
|
General and administrative
|
|
|
11,864
|
|
|
5.03
|
|
|
17,865
|
|
|
10.91
|
|
|
(6,001)
|
|
(34)%
|
|
|
(5.88)
|
|
(54)%
|
Accretion expense
|
|
|
575
|
|
|
0.24
|
|
|
343
|
|
|
0.21
|
|
|
232
|
|
68%
|
|
|
0.03
|
|
14%
|
Write-down of oil and natural gas properties
|
|
|
95,788
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
|
95,788
|
|
nm
|
|
|
nm
|
|
nm
|
Rig termination fee
|
|
|
—
|
|
|
—
|
|
|
3,641
|
|
|
nm
|
|
|
(3,641)
|
|
nm
|
|
|
nm
|
|
nm
|
Acquisition expense
|
|
|
1,954
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
|
1,954
|
|
nm
|
|
|
nm
|
|
nm
|
*nm =
not meaningful
Lease operating expenses.
These are daily costs incurred to extract oil and natural gas out of the ground, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
For the
three months ended
June 30, 2016
,
LOE
in
creased by
11%
to
$7.3
million
compared to
$6.6
million for
the same period of
2015
.
F
or the
three months ended
June 30, 2016
, LOE per BOE
decreased to
$5.97
per BOE
compared to
$7.59
per BOE for the same period of
2015
,
which was
primarily
attributable
to
improving
operational efficiency
,
reductions in workovers of vertical wells
and working with our service partners to achieve cost reducti
on
s
.
Higher production volumes
also
contributed to the
21%
per BOE decrease for the three months ended
June 30, 2016
.
The
in
crease in production was primarily attributable t
o an increased number of producing wells
as discussed above
.
For the
six months ended
,
June 30, 2016
, LOE
in
creased by
5%
to
$14.3
million compared to
$13.5
million for
the same period of
2015
.
For the
six months ended
,
June 30, 2016
, LOE per BOE decreased to
$6.05
per BOE compared to
$8.27
per BOE for the same period of
2015
, which was primarily attributable to
improving
operational efficiency
and
reduced vertical
workover
s,
and other
cost reductions
as
mentioned
above
. Higher production volumes also contributed to the
27%
per BOE decrease for the
six months ended
,
June 30, 2016
.
The
in
crease in production was primarily attributable t
o an increased number of producing wells
as discussed above
.
Production taxes.
Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
Production taxes for the
three months ended
June 30, 2016
de
creased by
17%
to
$2.5
million compared to
$3.0
million for the same period of
20
15
. The
de
crease was primarily due to
a decrease in ad valorem taxes
attributable to a lower valuation of our oil and gas properties by the taxing jurisdictions.
The decrease was
offset by an increase in severance taxes
, which was
attributable to an increase
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
in revenue
.
On a per BOE basis, production taxes for the three months ended
June 30, 2016
decreased by
41%
compared to the s
ame period of
2015
.
Production taxes for the
six months ended
June 30, 2016
decreased by
10%
to
$4.7
million compared to
$5.2
million for the same period of
201
5. The decrease was primarily due to a decrease in ad valorem taxes
attributable to a lower valuation of our oil and gas properties by the taxing jurisdictions. The decrease was
offset by an increase in severance taxes
, which was attributable to an increase in revenue
. On
a per BOE basis, production taxes for the
six months ended
June 30, 2016
decreased by
38%
compared to the same period of
2015
.
Depreciation, depletion and amortization (“DD&A”).
Under the full cost accounti
ng method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and e
quipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
For
the three months ended
June 30, 2016
,
D
D
&A
de
creased
7%
to
$16.3
million
compared to
$17.6
million for the same period of
2015
. For the
three months ended
June 30, 2016
,
DD&A decreased
34%
per BOE to
$13.31
per BOE compared to
$20.31
per BOE for the same period of
2015
.
The decrease is
attributable
to our increased estimated proved reserves relative to our depreciable asset base
and assumed future development costs related to undeveloped proved reserves. The decr
ease in our depreciable base was primarily related to the write-down of oil and natural gas properties
during
2015
and
the first quarter of 2016
.
For the
six months ended
June 30, 2016
, DD&A decreased
10%
to
$32.0
million compared to
$35.7
million for the same period of
2015
. For the
six months ended
June 30, 2016
, DD&A decreased
38%
per BOE to
$13.58
per BOE compared to
$21.80
per BOE for the same period of
2015
. The decrease is attributab
le to our increased estimated proved reserves relative to our depreciable asset base
and assumed future development costs related to undeveloped proved reserves. The decrease in our depreciable base was primarily related to the write-down of oil and natural gas properties during 2015
and the first quarter of 2016.
General and administrative, net of amounts capitalized (“G&A”).
These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional servi
ces, and legal compliance.
G&A for the
three months ended
June 30, 20
16
in
creased t
o $
6.3
million compared to
$5.8
million for the same period of
2015
.
G&A expenses for the periods indicated include the following
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
3.7
|
|
$
|
3.5
|
|
$
|
0.2
|
|
6%
|
Share-based compensation
|
|
|
0.6
|
|
|
0.5
|
|
|
0.1
|
|
20%
|
Fair value adjustments of cash-settled RSU awards
|
|
|
2.0
|
|
|
1.6
|
|
|
0.4
|
|
(25)%
|
Non-recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
Expense related to a threatened proxy contest
|
|
|
—
|
|
|
0.2
|
|
|
(0.2)
|
|
(100)%
|
Total G&A expenses
|
|
$
|
6.3
|
|
$
|
5.8
|
|
$
|
0.5
|
|
9%
|
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
G&A for the
six months ended
J
une 30, 20
16
decreased to
$11.9
mi
llion compared to
$17.9
million for the same period of
2015
.
G&A expenses for the periods indicated include the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
7.8
|
|
$
|
7.7
|
|
$
|
0.1
|
|
1%
|
Share-based compensation
|
|
|
1.2
|
|
|
1.0
|
|
|
0.2
|
|
20%
|
Fair value adjustments of cash-settled RSU awards
|
|
|
2.7
|
|
|
4.2
|
|
|
(1.5)
|
|
(36)%
|
Non-recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
Early retirement expenses
|
|
|
—
|
|
|
3.6
|
|
|
(3.6)
|
|
(100)%
|
Early retirement expenses related to share-based compensation
|
|
|
—
|
|
|
1.1
|
|
|
(1.1)
|
|
(100)%
|
Expense related to a threatened proxy contest
|
|
|
0.2
|
|
|
0.3
|
|
|
(0.1)
|
|
(33)%
|
Total G&A expenses
|
|
$
|
11.9
|
|
$
|
17.9
|
|
$
|
(6.0)
|
|
(34)%
|
Accretion expense.
The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations.
Accretion expense related to our A
RO
in
creased
195%
an
d
68%
for
the
three and six months ended June 30, 2016
,
respectively,
c
ompared to the same period
s
of
2015
. Accretion expense generally correlates with the Company’s ARO
,
which was
$6.1
million at
June 30, 2016
as compared to
$4.1
million at
June 30, 2015
. See
Note 9
in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.
Rig termination fee.
During the first quarter of 2015, the Company recognized $3.1 million in expense related to the early termination of the contract for its vertical rig. In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015). The Company paid approximately $3.1 million in reduced rental payments over the remainder of the lease term, which ended November 2015.
Acquisition expense.
Acquisition expense for the
three and six months ended June 30, 2016
we
re related to costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Write-down of oil and natural gas properties.
Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount).
These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.
For the
three and six months ended June 30, 2016
,
the Company recognized write-down
s
of oil and natural gas properties of
$61
million
and
$95.8
million, respectively,
as a result of the ceiling test limitation. No write-down was recognized during
th
e same period
s
of
201
5
. See Note
2
in the Footnotes to the Financial Statements for additional information. Based on prevailing commodity prices in the current environment, we could incur additional ceiling test write-downs in the
future.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Other Income and Expenses and Preferred Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
$ Change
|
|
% Change
|
Interest expense, net of capitalized amounts
|
|
$
|
4,180
|
|
$
|
5,106
|
|
$
|
(926)
|
|
(18)%
|
Loss on derivative contracts
|
|
|
15,484
|
|
|
8,249
|
|
|
7,235
|
|
88%
|
Other income, net
|
|
|
(96)
|
|
|
(41)
|
|
|
(55)
|
|
134%
|
Total
|
|
$
|
19,568
|
|
$
|
13,314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit
|
|
$
|
—
|
|
$
|
(2,116)
|
|
$
|
2,116
|
|
(100)%
|
Preferred stock dividends
|
|
|
(1,823)
|
|
|
(1,973)
|
|
|
150
|
|
(8)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
$ Change
|
|
% Change
|
Interest expense, net of capitalized amounts
|
|
$
|
9,671
|
|
$
|
9,964
|
|
$
|
(293)
|
|
(3)%
|
Loss on derivative contracts
|
|
|
16,416
|
|
|
5,820
|
|
|
10,596
|
|
182%
|
Other income, net
|
|
|
(177)
|
|
|
(85)
|
|
|
(92)
|
|
108%
|
Total
|
|
$
|
25,910
|
|
$
|
15,699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit
|
|
$
|
—
|
|
$
|
(7,193)
|
|
$
|
7,193
|
|
(100)%
|
Preferred stock dividends
|
|
|
(3,647)
|
|
|
(3,947)
|
|
|
300
|
|
(8)%
|
Interest expense
, net of capitalized amounts
.
We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.
Interest expense
, net of capitalized amounts,
incurred during the three months ended
June 30, 2016
de
creased
$0.9
million compared to the same period of 2015. The
de
crease is primarily attributable to
a $0.8 million increase in capitalized interest compared to the 2015 period, resulting from a higher average unevaluated property balance for the three months ended June 30, 2016 as compared to the same period of 2015.
The increase in unevaluated property was primarily due to acquisitions costs.
Also contributing to the decrease was a $0.1 million decrease in interest expense related to our debt.
Interest expense
, net of capitalized amounts,
incurred during the
six months ended
June 30, 2016
de
creased
$0.3
million compared to the same period of 2015. The
de
crease is primarily attributable to a
$0.4
million
in
crease in capitalized interest compared to the 2015 period, resulting from a
high
er average unevaluated property balance for the
six months ended
June 30, 2016
as compared to the same period of 2015.
The increase in unevaluated property was primarily due to acquisitions costs.
Offsetting
the
de
crease was a
$0.1
million
in
crease in interest expense related to our debt.
See Note
5
in the Footnotes to the Financial Statements for additional information on our debt.
(Gain) loss on derivative contracts.
We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i)
(
gain
)
loss related to fair value adjustments on our open derivative contracts and (ii)
(
gains
)
losses on settlements of derivative contracts for positions that have settled within the period.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
For the
three months ended
June 30, 2016
, the net loss on derivative contracts was
$15.5
million compared to a
n
$8.2
million net
loss
for the same period of 2015. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
2016
|
|
2015
|
|
$ Change
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
3.7
|
|
$
|
4.5
|
|
$
|
(0.8)
|
Net loss on fair value adjustments
|
|
|
(18.5)
|
|
|
(12.7)
|
|
|
(5.8)
|
Total loss
|
|
$
|
(14.8)
|
|
$
|
(8.2)
|
|
$
|
(6.6)
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
0.3
|
|
$
|
0.5
|
|
$
|
(0.2)
|
Net loss on fair value adjustments
|
|
|
(1.0)
|
|
|
(0.5)
|
|
|
(0.5)
|
Total loss
|
|
$
|
(0.7)
|
|
$
|
—
|
|
$
|
(0.7)
|
|
|
|
|
|
|
|
|
|
|
Total loss on derivative contracts
|
|
$
|
(15.5)
|
|
$
|
(8.2)
|
|
$
|
(7.2)
|
For the
six months ended
June 30, 2016
, the net loss on derivative contracts was
$16.4
million compared to a
$5.8
million net
loss
for the same period of 2015. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
11.2
|
|
$
|
14.5
|
|
$
|
(3.3)
|
Net loss on fair value adjustments
|
|
|
(27.6)
|
|
|
(20.5)
|
|
|
(7.1)
|
Total loss
|
|
$
|
(16.4)
|
|
$
|
(6.0)
|
|
$
|
(10.4)
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
0.5
|
|
$
|
0.8
|
|
$
|
(0.3)
|
Net loss on fair value adjustments
|
|
|
(0.5)
|
|
|
(0.6)
|
|
|
0.1
|
Total gain (loss)
|
|
$
|
—
|
|
$
|
0.2
|
|
$
|
(0.2)
|
|
|
|
|
|
|
|
|
|
|
Total loss on derivative contracts
|
|
$
|
(16.4)
|
|
$
|
(5.8)
|
|
$
|
(10.6)
|
See
Notes 6
and
7
in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Income tax expense.
The Company had no income tax expense for the
three and six months ended June 30, 2016
compared to
an
income tax benefit of
$2.1
million
and $7.2 million
for the same period
s
of 2015. The change in income tax expense is primarily related to recording a valuation allowance
of
$147.5
million
at
June 30, 2016
and the difference in the amount of income (loss) before income taxes between periods. See Note 8 in the Footnotes to the Financial Statements for additional information.
Preferred Stock dividends.
Preferred Stock dividends for the
three and six months ended June 30, 2016
were
$1.8
million
and
$3.6
million, respectively,
as compared to
$2.0
million
and
$3.9
million
for the same period
s
of 2015
, respectively.
The decrease was due to a decrease in the number of preferred shares outstanding attributable to a partial share conversion in February 2016 in which
the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock.
Dividen
ds reflect a 10% dividend rate
. See
Note 10
in the Footnotes to the Financial Statements
for additional information.