Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
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 Basin. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. 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 shale. 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 swa
ps.
Our production was approximately
79%
oil and
21%
natural gas for the
three months ended
March 31, 2016
. On
March 31, 2016
, our
net
acreage position in the Permian Basin was approximatel
y
17,675
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, 20
14 to
$45.92
o
n
April 29, 2016
. For the three months ended
March 31, 2016
, the average NYMEX price for a barrel of oil was
$33.58
per Bbl compared to
$48.58
per Bbl for the same period of
2015
. The NYMEX price for a barrel of oil ranged from a low of
$26.21
per Bbl to a high of
$41.45
per Bbl for the three months ended
March 31, 2016
.
For the three months ended
March 31, 2016
, the average NYMEX price for natural gas w
as
$2.09
per MMBtu compared to
$2.98
per MMBtu for the same period in
2015
. The NYMEX price for natural gas ranged from a low of
$1.64
per MMBtu to a high of
$2.47
p
er MMBtu for the three months ended
March 31, 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 o
f proved oil and natural gas properties exceeds the full cost ceiling. At March 31, 2016, the prices used in determining the estimated fu
ture net cash flows from proved reserves wer
e $43.56 per barrel of oil and $2.59 per Mcf of natural gas. For the period ended March 31, 2016, the Company recognized a write-down of oil and natural gas properties
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
of $34.8 million as a result of the ceiling test limitation. Based on prevailing commodity prices in the current environment, we expect to incur additional ceiling test write-downs in the f
uture. However, we do not expect such prevailing commodity prices to have significant adverse effects on our proved oil and gas reserves. See
Note 2
in the Footnotes to the Financial Statements for more information.
The table below presents results of the full cost ceiling test as of March 31, 2016, along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of March 31, 2016 and, accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to March 31, 2016 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling te
st.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-Month Average Prices
|
|
Excess (Deficit) of
full cost ceiling over net capitalized costs
|
|
(Increase) Decrease in excess of full cost ceiling over net capitalized costs
|
Pricing Scenarios
|
|
Oil ($/Bbl)
|
|
Natural gas ($/Mcf)
|
|
(in thousands)
|
March 31, 2016 Actual
|
|
$
|
43.56
|
|
$
|
2.59
|
|
$
|
(34,776)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas +10%
|
|
$
|
47.91
|
|
$
|
2.85
|
|
$
|
63,278
|
|
$
|
98,054
|
Oil and natural gas -10%
|
|
|
39.20
|
|
|
2.33
|
|
|
(132,815)
|
|
|
(98,039)
|
Oil price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil +10%
|
|
$
|
47.91
|
|
$
|
2.59
|
|
$
|
54,419
|
|
$
|
89,195
|
Oil -10%
|
|
|
39.20
|
|
|
2.59
|
|
|
(123,964)
|
|
|
(89,188)
|
Natural gas sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas +10%
|
|
$
|
43.56
|
|
$
|
2.85
|
|
$
|
(25,917)
|
|
$
|
8,859
|
Natural gas -10%
|
|
|
43.56
|
|
|
2.33
|
|
|
(43,628)
|
|
|
(8,852)
|
Operational Highlights
Our production grew
47%
for
the three months ended
March 31, 2016
,
compared to the same period of
2015
, increasing to
1,132
MBOE from
771
MBOE
for the comparative three months period.
|
|
|
|
|
|
|
|
|
|
|
Net Production (MBOE)
|
|
|
Three Months Ended March 31,
|
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
Southern Midland Basin
|
|
500
|
|
445
|
|
55
|
|
12%
|
Central Midland Basin
|
|
632
|
|
325
|
|
307
|
|
94%
|
Other
|
|
—
|
|
1
|
|
(1)
|
|
(100)%
|
Total
|
|
1,132
|
|
771
|
|
361
|
|
47%
|
The fo
llowing table sets forth productive wells as of
March 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
Oil Wells
|
|
Natural Gas Wells
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Working interest
|
|
329
|
|
258.6
|
|
—
|
|
—
|
Royalty interest
|
|
3
|
|
0.1
|
|
—
|
|
—
|
Total
|
|
332
|
|
258.7
|
|
—
|
|
—
|
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 natural gas.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
The following table summarizes the Company’s drilling activity in the Permian Basin for the three months ended March 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31, 2016
|
|
|
Drilled
|
|
Completed (a)
|
|
Awaiting Completion
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Central Midland Basin horizontal wells
|
|
5
|
|
4.3
|
|
9
|
|
7.1
|
|
2
|
|
1.8
|
|
(a)
|
|
Completions include wells drilled prior to
201
6
.
|
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
common stock offering
s
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 Ba
sin. As of March 31, 2016, there was no balance outstanding on the Credit Facility
, and the
borrowing base
was reaffirmed at $300 million on April 7, 2016.
For the
three months ended March 31, 2016
, cash and cash equivalents increa
sed
$8.3
million to
$9.5
milli
on compared to
$1.2
million
at March 31, 2015.
Liquidity and cash flow
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
(dollars in millions)
|
|
2016
|
|
2015
|
Net cash provided by operating activities
|
|
$
|
16.1
|
|
$
|
6.1
|
Net cash used in investing activities
|
|
|
(60.9)
|
|
|
(70.5)
|
Net cash provided by financing activities
|
|
|
53.1
|
|
|
65.6
|
Net change in cash
|
|
$
|
8.3
|
|
$
|
1.2
|
Operating
activities.
For the
three months ended March 31, 2016
, net cash
provided by
operating activities was
$16.1
million compared to
net cash provided by operating activities of
$6.1
million for the same period in
2015
. The
change
was predominantly attributable to the following:
|
·
|
|
A
reduction in gains on the 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 7
and
8
in the Footnotes to the Financial St
atements 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
three months ended March 31, 2016
, net cash used in investing activities was
$60.9
million compared to
$70.5
million for the same period in
2015
. The
$9.6
million decrease in cash used in investing activities was primarily attributable to the following:
|
·
|
|
A
$
21.1 million decrease in operational expenditures due to the release of a vertical rig in April 2015 and working with our service partners to achieve reductions in drilling and completion costs during 2015; and
|
|
·
|
|
The $10.2 million increase driven by the acquisition of an additional 4.9% working interest (3.7% net revenue interest) in our Cass
e
lman-Bohannon fields during the three months ended March 31, 2016.
|
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Our investing activities, on a cash basis, include the following for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
2016
|
|
2015
|
|
$ Change
|
Southern Midland Basin
|
|
$
|
7.4
|
|
$
|
55.1
|
|
$
|
(47.7)
|
Central Midland Basin
|
|
|
35.4
|
|
|
8.8
|
|
|
26.6
|
Total operational expenditures (a)
|
|
|
42.8
|
|
|
63.9
|
|
|
(21.1)
|
|
|
|
|
|
|
|
|
|
|
Capitalized general and administrative costs allocated directly to
|
|
|
|
|
|
|
|
|
|
exploration and development projects
|
|
|
3.3
|
|
|
2.8
|
|
|
0.5
|
Capitalized interest
|
|
|
2.3
|
|
|
2.9
|
|
|
(0.6)
|
Total capitalized general and administrative and interest costs (a)
|
|
|
5.6
|
|
|
5.7
|
|
|
(0.1)
|
|
|
|
|
|
|
|
|
|
|
Total operational expenditures inclusive of capitalized general
|
|
|
|
|
|
|
|
|
|
and administrative and interest costs (a)
|
|
|
48.4
|
|
|
69.6
|
|
|
(21.2)
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
10.2
|
|
|
—
|
|
|
10.2
|
Other
|
|
|
2.3
|
|
|
1.2
|
|
|
1.1
|
Proceeds from the sale of mineral interest and equipment
|
|
|
—
|
|
|
(0.3)
|
|
|
0.3
|
Total investing activities
|
|
$
|
60.9
|
|
$
|
70.5
|
|
$
|
(9.6)
|
|
(a)
|
|
On an accrual (GAAP) basis, which is the metho
dology used for establishing our annual capital budget, operational expenditures for the three months ended
March 31, 2016
we
re
$35
million. Inclusive of
capitalized general and administrative and interest costs, total operational expenditures were
$41.6
million.
|
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See
Note 3
in the Footnotes to t
he 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
C
redit
F
acility, term debt and equity offerings.
For the
three months ended March 31, 2016
, net cash provided by financing activities wa
s
$53.1
millio
n compared to cash provided by financing activities of
$65.6
million during the same period of
2015
.
The change
in net cash provided by financing activities was primarily attributable to the following:
|
·
|
|
Payments, n
et
of
borrowings
,
on our
C
redit
F
acility
we
re
$40
mi
llion,
$42
million less than the same period of 2015; and
|
|
·
|
|
A
$29.4
million increase in proceeds resulting from a common stock offering in March 2016 as compared to proceeds resulting from a common stock offering in March 2015.
|
See Note 11 in the Footnotes to the Financial Statements for additional information on our equity offerings.
Operational Capital Budget and First Quarter S
ummary
During
the three months ended March 31, 2016, we transitioned from a two-rig to a one-rig program. Our horizontal drilling program was primarily focused on the Lower Spraberry zone in the Central Midland Basin with lateral lengths ranging from approximately 5,000’ to 9,000’ and well completions from two to three well pads.
Subsequent to the announcement of pending transactions (se
e Note 4 i
n the Footnotes to Financial Statements), our operational capital guidance was updated from $75
to
$80 million to $95
to
$105 million, which reflects an increase in expenditures related to incremental completions and infrastructure investments for future development of the acquired properties.
Operational capital expenditures on an accrual basis were
$35
million for the three months ended March 31, 2016.
In addition to the operational capital expenditures abo
ve, $4.3 million of capitalized general and administrative expenses and $2.4 million of capitalized interest expenses were accrued in the three months
ended March 31, 2016.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Based upon current commodity price expectations for 2016, we b
elieve that our cash flow from operations and available borrowings under our Credit Facility will be su
fficient to fund our remaining 2016 capital program, including working capital requirements.
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 March 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
% Change
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
892
|
|
|
638
|
|
|
254
|
|
40%
|
Natural gas (MMcf)
|
|
|
1,443
|
|
|
801
|
|
|
642
|
|
80%
|
Total (MBOE)
|
|
|
1,132
|
|
|
771
|
|
|
361
|
|
47%
|
Average daily production (BOE/d)
|
|
|
12,440
|
|
|
8,567
|
|
|
3,873
|
|
45%
|
% oil (BOE basis)
|
|
|
79%
|
|
|
83%
|
|
|
|
|
|
Average realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
30.77
|
|
$
|
43.74
|
|
$
|
(12.97)
|
|
(30)%
|
Oil (Bbl) (including impact of cash settled derivatives)
|
|
|
39.18
|
|
|
59.34
|
|
|
(20.16)
|
|
(34)%
|
Natural gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
2.26
|
|
$
|
3.10
|
|
$
|
(0.84)
|
|
(27)%
|
Natural gas (Mcf) (including impact of cash settled derivatives)
|
|
|
2.40
|
|
|
3.59
|
|
|
(1.19)
|
|
(33)%
|
Total (BOE) (excluding impact of cash settled derivatives)
|
|
$
|
27.12
|
|
$
|
39.42
|
|
$
|
(12.30)
|
|
(31)%
|
Total (BOE) (including impact of cash settled derivatives)
|
|
|
33.93
|
|
|
52.83
|
|
|
(18.90)
|
|
(36)%
|
Oil and natural gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
27,443
|
|
$
|
27,909
|
|
$
|
(466)
|
|
(2)%
|
Natural gas revenue
|
|
|
3,255
|
|
|
2,482
|
|
|
773
|
|
31%
|
Total
|
|
$
|
30,698
|
|
$
|
30,391
|
|
$
|
307
|
|
1%
|
Additional per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
Sales price (excluding impact of cash settled derivatives)
|
|
$
|
27.12
|
|
$
|
39.42
|
|
$
|
(12.30)
|
|
(31)%
|
Lease operating expense
|
|
|
6.15
|
|
|
9.03
|
|
|
(2.88)
|
|
(32)%
|
Production taxes
|
|
|
1.96
|
|
|
2.94
|
|
|
(0.98)
|
|
(33)%
|
Operating margin
|
|
$
|
19.01
|
|
$
|
27.45
|
|
$
|
(8.44)
|
|
(31)%
|
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 in the underlying commodity prices.
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oil
|
|
Natural Gas
|
|
Total
|
Revenues for the three months ended March 31, 2015
|
|
$
|
27,909
|
|
$
|
2,482
|
|
$
|
30,391
|
Volume increase
|
|
|
11,121
|
|
|
1,985
|
|
|
13,106
|
Price decrease
|
|
|
(11,587)
|
|
|
(1,212)
|
|
|
(12,799)
|
Net increase (decrease)
|
|
|
(466)
|
|
|
773
|
|
|
307
|
Revenues for the three months ended March 31, 2016
|
|
$
|
27,443
|
|
$
|
3,255
|
|
$
|
30,698
|
Oil revenue
For the quarter ended
March 31, 2016
, oil revenues of
$27.4
million
de
creased
$0.5
million, or
2%
, compared to revenues of
$27.9
million for the same period of
2015
.
T
he
de
crease
in oil revenue was
primarily attributable to a
30%
decrease in the average realized sales price
, which fell to
$30.77
per Bbl from
$43.74
per Bbl, and was predominantly
offset by a
40%
increase in production. 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.
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
Natural gas revenue (including NGLs)
Natural gas revenues of
$3.3
million
in
creased
$0.8
million, or
31%
, during the
three months ended
March 31, 2016
compared to
$2.5
million for the same period of
2015
. The
in
crease primarily relates to
a
80%
increase in natural gas volumes and was pr
edominant
ly offset by
a
27%
decrease in the average price realized, which fell to
$2.26
per Mcf from
$3.10
per Mcf
,
reflecti
ng
decreases 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.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Three Months Ended March 31,
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
|
|
2016
|
|
BOE
|
|
2015
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
6,957
|
|
$
|
6.15
|
|
$
|
6,959
|
|
$
|
9.03
|
|
(2)
|
|
(0)%
|
|
(2.88)
|
|
(32)%
|
Production taxes
|
|
|
2,220
|
|
|
1.96
|
|
|
2,265
|
|
|
2.94
|
|
(45)
|
|
(2)%
|
|
(0.98)
|
|
(33)%
|
Depreciation, depletion and amortization
|
|
|
15,722
|
|
|
13.89
|
|
|
18,104
|
|
|
23.48
|
|
(2,382)
|
|
(13)%
|
|
(9.59)
|
|
(41)%
|
General and administrative
|
|
|
5,562
|
|
|
4.91
|
|
|
12,102
|
|
|
15.70
|
|
(6,540)
|
|
(54)%
|
|
(10.79)
|
|
(69)%
|
Accretion expense
|
|
|
180
|
|
|
0.16
|
|
|
209
|
|
|
0.27
|
|
(29)
|
|
(14)%
|
|
(0.11)
|
|
(41)%
|
Rig termination fee
|
|
|
—
|
|
|
—
|
|
|
3,641
|
|
|
nm
|
|
(3,641)
|
|
nm
|
|
nm
|
|
nm
|
Acquisition expense
|
|
|
48
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
48
|
|
nm
|
|
nm
|
|
nm
|
Write-down of oil and natural gas properties
|
|
|
34,776
|
|
|
nm
|
|
|
—
|
|
|
—
|
|
34,776
|
|
nm
|
|
nm
|
|
nm
|
*nm = not meani
ngful
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
March 31, 2016
,
LOE
of
$7.0
million remained consistent with
the same period of
2015
.
F
or the
three months ended
March 31, 2016
, LOE per BOE
decreased to
$6.15
per BOE
compared to
$9.03
per BOE for the same period of
2015
,
which was
primarily
attributable
to
maintaining operational efficiency as we grow our asset base and working with our service partners to achieve cost reduction
s
.
Higher production volumes
also
contributed to the
32%
per BOE decrease for the
three months ended
March 31, 20
16
.
Production taxes.
P
roduction 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 a
nd gas properties.
Production taxes for the
three months ended
March 31, 2016
de
creased by
2%
to
$2.2
million compared to
$2.3
million for the same period of
2015
. The
de
crease was primarily due to
a decrease in ad valorem taxes
, offset by an increase
in severance taxes.
On a per BOE basis, production taxes for the
three months ended
March 31, 2016
decreased by
33%
compared to the same period of
2015
.
Depreciation, depletion and amortization (“DD&A”).
Under the full cost accounting 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 equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
For
the three months ended March 31, 2016,
D
D
&A
de
creased
13%
to
$15.7
million
compared to
$18.1
million for the
same period of
2015
. For the
three months ended
March 31, 2016
,
DD&A decreased
41%
per BOE to
$13.89
per BOE compared to
$23.48
per BOE
|
|
|
Callon Petroleum Company
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
Table of Contents
|
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 decrease in our depreciable base was primarily related to the write-down of oil and natural gas propert
ies
during
2015.
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 compensati
on plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.
G&A for the
three months ended
March 31, 2016
de
creased
to $
5.6
m
illion compared to
$12.1
million for the same period of
2015
.
G&A expenses for the periods indicated include the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
2016
|
|
2015
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
4.2
|
|
$
|
4.2
|
|
$
|
—
|
|
—%
|
Share-based compensation
|
|
|
0.5
|
|
|
0.5
|
|
|
—
|
|
—%
|
Fair value adjustments of cash-settled RSU awards
|
|
|
0.7
|
|
|
2.6
|
|
|
(1.9)
|
|
73%
|
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
|
|
|
0.1
|
|
|
0.1
|
|
100%
|
Total G&A expenses
|
|
$
|
5.6
|
|
$
|
12.1
|
|
$
|
(6.5)
|
|
(54)%
|
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.
Accreti
on expense related to our A
RO decreased
14%
for
the three months ended March 31, 2016
,
c
ompared to the same period of
2015
. Accretion expense generally correlates with the Company’s ARO
,
wh
ich was
$5.3
milli
on at
March 31, 2016
as compared to
$6.3
million a
t
March 31, 2015
. See
Note 10
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 months ended March 31, 20
1
6
,
were 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).
For the three months ended March 31, 2016
, the Company recognized a write-down of oil and natural gas properties of
$34.8
million as a result of the ceiling test limitation. No write-down was recognized during
the same period 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 a
nd Expenses and Preferred Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
$ Change
|
|
% Change
|
Interest expense
|
|
$
|
5,491
|
|
$
|
4,858
|
|
$
|
633
|
|
13%
|
(Gain) loss on derivative contracts
|
|
|
932
|
|
|
(2,429)
|
|
|
3,361
|
|
(138)%
|
Other income, net
|
|
|
(81)
|
|
|
(44)
|
|
|
(37)
|
|
84%
|
Total
|
|
$
|
6,342
|
|
$
|
2,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
—
|
|
$
|
(5,077)
|
|
$
|
5,077
|
|
(100)%
|
Preferred stock dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
150
|
|
(8)%
|
Interest expense
.
Inte
rest expense incurred during the
three months ended
March 31, 2016
increa
sed
$0.6
m
illion compared to the same period of
2015
. The increase is primarily attributable t
o
a
$0.5
million
de
crease in capitalized interest compared to the 2015 perio
d, resulting from a
low
er average unevaluated property balance for the
three months ended
March 31, 2016
as c
ompared to the same period of 2015.
Also contributing to the increase was a $0.1 million increase in interest expense related to our debt.
(Gain) loss on derivative contract
s
.
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.
For the three months ended March 31, 2016, the
net loss on de
rivative contracts
was
$0.9
m
illion compared to a
$2.4
million net gain 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
|
|
$
|
7.5
|
|
$
|
9.9
|
|
$
|
(2.4)
|
Net loss on fair value adjustments
|
|
|
(9.1)
|
|
|
(7.8)
|
|
|
(1.3)
|
Total gain (loss)
|
|
$
|
(1.6)
|
|
$
|
2.1
|
|
$
|
(3.7)
|
|
|
|
|
|
|
|
|
|
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
0.2
|
|
$
|
0.4
|
|
$
|
(0.2)
|
Net gain (loss) on fair value adjustments
|
|
|
0.5
|
|
|
(0.1)
|
|
|
0.6
|
Total gain
|
|
$
|
0.7
|
|
$
|
0.3
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivative contracts
|
|
$
|
(0.9)
|
|
$
|
2.4
|
|
$
|
(3.3)
|
See
Notes 7
and
8
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 months ended
March 31, 2016
compared to
an
income tax
benefit
of
$5.1
million for the same period of
2015
. Th
e
change
in income tax expense is primarily related to recording a valuation allowance o
f
$123.1
million for the three months ended
March 31, 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 months ended March 31
, 2016 were
$1.8
million as compared to
$2.0
million for the same period of
2015
. The decrease
wa
s due to a decrease in the number of p
referred 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 11
in the Footnotes to the Financial Statements
for additional infor
mation.