|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
In August 2016, the Financial Accounting Standards Board issued accounting standards update No. 2016-15,
Statement of Cash Flows (Topic 230):
Classification of Certain Cash Receipts and Cash Payments
(“ASU 2016-15”).
The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with
c
oupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial inter
e
sts in securitization transactions, and separately identifiable cash flows and application of the predominance principle
.
The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures.
Recently adopted accounting policies
In November 2015, the FASB issued ASU No. 2015-17,
Balance Sheet Classification of Deferred Taxes
(“ASU 2015-17”), which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet. The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. As of
September 30, 2016
, the Company adopted this ASU, which does not have a material impact on its financial state
ments.
Note 2 – Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its exploration and development activities.
Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar 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
r
equire 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
September 30, 2016
, the
average realized
prices used in determining the estimated future net cash flows from proved reserves were
$
38.92
per barrel of oil and
$2.53
per Mcf of natural gas.
For the three months ended
September 30, 2016
no
write-down of oil and natural gas properties was recognized
as a result of the ceiling test limitation.
F
or the
nine
months
ended
September 30, 2016
, the Company recognized
a
write-down of oi
l and natural gas properties of
$95,788
as a result of the ceiling test limitation.
Note 3 - Acquisitions
Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
2016 acquisitions
On August 3, 2016, the Company entered into a definitive purchase and sale agreement for the acquisition of an addition
al
4.0%
working interest (
3.0%
net revenue interest) in the Casselman-Bohannon fields for total cash consideration o
f
$13,000
,
excluding customary purchase price adjustments. Following the completion of this acquisition the Company will own approximately
75.3%
working interest (
58.5%
net revenue interest) in the Casselman-Bohannon fields.
The following table summarizes the estimated acquisition date fair values of the net assets to be acquired in the acquisition:
|
|
|
|
Evaluated oil and natural gas properties
|
|
$
|
6,492
|
Unevaluated oil and natural gas properties
|
|
|
6,508
|
Net assets acquired
|
|
$
|
13,000
|
On
May
26
, 2016, the Company completed the acquisition
of
17,298
gross (
14,089
net) acres primarily located in Howard County, Texas from
BSM Energy LP, Crux Energy LP and Zaniah Energy LP
, for
total cash consideration
of
$
220,000
and
9,333,333
shares of common stock
for a total purchase price of $
329,573
,
excluding
customary purchase price adjust
ments
(the “Big Star Transaction”)
. The Company
acquired
an
81%
average working interest (
61%
average net revenue interest) in the
properties acquired in the
Big Star Transaction
.
The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. The following table summarizes the estimated acquisition date fair values of the net assets to be acquired in the
a
cquisition:
|
|
|
|
Evaluated oil and natural gas properties
|
|
$
|
96,194
|
Unevaluated oil and natural gas properties
|
|
|
233,387
|
Asset retirement obligations
|
|
|
(8)
|
Net assets acquired
|
|
$
|
329,573
|
The following unaudited summary pro forma financial information fo
r the three and
nine
months ended
September
30, 2016 has
been presented for illustrative purposes only and do
e
s not purport to represent what the Company’s results of operations would have been if the Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Big Star Transaction occurred as of January 1, 201
5
. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, includ
ing
those pertaining to
revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense,
write-down of oil and natural gas properties,
accretion expense, interest expense and capitalized interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Revenues
|
|
$
|
55,927
|
|
$
|
41,501
|
|
$
|
140,937
|
|
$
|
119,561
|
Income from operations
|
|
|
16,651
|
|
|
(17,644)
|
|
|
(68,753)
|
|
|
(25,339)
|
Income available to common stockholders
|
|
|
19,315
|
|
|
(43,720)
|
|
|
(88,886)
|
|
|
(55,896)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
$
|
(0.43)
|
|
$
|
(0.79)
|
|
$
|
(0.57)
|
Diluted
|
|
$
|
0.14
|
|
$
|
(0.43)
|
|
$
|
(0.79)
|
|
$
|
(0.57)
|
From the date of the acquisition through the period ende
d
September
30, 2016, the properties asso
ciated
with the Big Star Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.
O
n
May 16
, 2016, the Company
completed
the following transactions (collectively, the “AMI Transaction”)
for an aggregate
net
cash
purchase price
of
$
33,012
,
excluding
customary purchase price adjustments.
Key elements of the AMI Transaction include:
|
·
|
|
Formation of an area of mutual interest with TRP Energy, LLC (“TRP”) in western Reagan County, Texas, through the joint acquisition from a private party of
4,745
net acres (with a
55%
share to Callon) north of the Garrison Draw field; and
|
|
·
|
|
Callon’s simultaneous sale of a
27.5
%
interest in the Garrison Draw field to TRP.
|
The following table summarize
s
the acquisition date fair values of the net assets acquired, including customary purchase price adjustments:
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
|
|
|
|
Evaluated oil and natural gas properties
|
|
$
|
15,951
|
Unevaluated oil and natural gas properties
|
|
|
17,069
|
Asset retirement obligations
|
|
|
(8)
|
Net assets acquired
|
|
$
|
33,012
|
On January 18, 2016, the Company completed the acquisition of an additional
4.9%
working interest (
3.7%
net revenue interest) in the Ca
sselman-Bohannon fields for an aggregate
cash
purchase price
of
$
10,183
,
including
customary purchase price adjustments. The following table summarizes the acquisition date fair values of the net assets acquired, including customary purchase price adjustments:
|
|
|
|
Evaluated oil and natural gas properties
|
|
$
|
5,527
|
Unevaluated oil and natural gas properties
|
|
|
4,656
|
Net assets acquired
|
|
$
|
10,183
|
Subsequent event
On October 20, 2016, the Company completed the acquisition of
6,904
gross (
5,952
net) acres primarily located in Howard County, Texas fr
om
P
l
ymouth Petroleum, LLC
and additional sellers that exercised their “tag-along” sales rights,
for t
otal cash consideration
of
$340,686
,
exclu
ding customary purchase pric
e adjustments (the “
Plymouth
Transaction
”). The Company funded the cash purchase price with the net proceeds of an equity offering
(see Note 10 for additional information regarding the equity offering). The Company acquired an
82%
average working interest (
62%
average net revenue interest) in the properties acquired in
the
Plymouth
Transaction
.
In September 2016
,
in connection with the execution of the purchase and sale agreement for the Plymouth
Transaction
,
the Company paid a deposit in the amount of $
32,700
to a third party escrow agent, which was recorded as
Acquisition deposit on the balance sheet as of September 30, 2016.
Note 4 - Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
(share amounts in thousands)
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
Net income (loss)
|
|
$
|
21,139
|
|
$
|
(111,805)
|
|
$
|
(90,067)
|
|
$
|
(126,969)
|
Preferred stock dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
(5,471)
|
|
|
(5,921)
|
Income (loss) available to common stockholders
|
|
$
|
19,315
|
|
$
|
(113,779)
|
|
$
|
(95,538)
|
|
$
|
(132,890)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
136,983
|
|
|
66,277
|
|
|
112,925
|
|
|
63,265
|
Dilutive impact of restricted stock
|
|
|
500
|
|
|
—
|
|
|
—
|
|
|
—
|
Weighted average shares outstanding for diluted income (loss) per share
|
|
|
137,483
|
|
|
66,277
|
|
|
112,925
|
|
|
63,265
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income (loss) per share
|
|
$
|
0.14
|
|
$
|
(1.72)
|
|
$
|
(0.85)
|
|
$
|
(2.10)
|
Diluted income (loss) per share
|
|
$
|
0.14
|
|
$
|
(1.72)
|
|
$
|
(0.85)
|
|
$
|
(2.10)
|
|
|
|
|
|
|
|
|
|
|
Stock options (a)
|
|
|
15
|
|
|
15
|
|
|
15
|
|
|
15
|
Restricted stock (a)
|
|
|
25
|
|
|
159
|
|
|
25
|
|
|
159
|
|
(a)
|
|
Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive
.
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
Note 5 - Borrowings
The Company’s borrowings consisted of the following at:
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
December 31, 2015
|
Principal components
|
|
|
|
|
|
|
Senior secured revolving credit facility
|
|
$
|
—
|
|
$
|
40,000
|
Secured second lien term loan
|
|
|
300,000
|
|
|
300,000
|
Total principal outstanding
|
|
|
300,000
|
|
|
340,000
|
Secured second lien term loan, unamortized deferred financing costs
|
|
|
(9,915)
|
|
|
(11,435)
|
Total carrying value of borrowings
|
|
$
|
290,085
|
|
$
|
328,565
|
Senior secured revolving credit facility (the “Credit Facility”)
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date
of
March 11, 2019
.
JPMorgan Chase Bank, N.A. is Administrative Agent, and participa
nts include several institutional
lenders.
The total notional amount available under the Credit Facility is
$500,000
. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of
September 30, 2016
,
the Credit Facility’s borrowing base was
$385,000
. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.
Effecti
ve July 13, 2016, the Credit Facility’s borrowing base was increased to
$385,000
and the Com
pany’s capacity to hedge oil and natural gas volumes was effectively increased with a change in the capacity calculation to a percentage of total proved reserves from proved producing reserves. In addition, the interest rate for borrowings under the Credit Facility was increased
0.25%
across all tiers of the pricing grid, resulting in a range of interest costs equal to LIBOR plus
2.00%
to
3.00%
. There were no modifications to other terms or covenants of the Credit Facility.
As of
September 30, 2016
, the
re was
no
balance outstanding on the Credit Facility
.
For the
quarter
ended
September 30, 2016
, t
he Credit Facility had a
weighted-average interest rate of
2.92%
, calculated as the LIBOR plus a tiered rate ranging from
2.00%
to
3.00%
, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of
0.5%
per annum, payable quarterly, on the unused portion of the borrowing
base.
Secured second lien term loan (the “Term Loan”
)
On October 8, 2014, the Company entered into the Term Loan with an aggregate amount of up to
$300,000
and a maturity date of
October 8, 2021
. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. The Term Loan may be prepaid at the Company’s option, subject to a prepayment premium.
The prepayment amount
would be
(i)
102%
of principal
if the prepayment event occur
red
prior to October 8, 2016,
(ii)
101%
of principal
if the prepayment event occur
red
on or after October 8, 201
6
,
but before October 8, 201
7
, and (ii
i
) 100%
of principal
for prepayments made on or after October 8, 201
7
. The Term Loan
wa
s secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agr
eement.
As of
September 30, 2016
, the balance outstanding on the Term Loan was
$300,000
with an interest rate of
8.5%
, calculated at a rate of LIBOR
(subject to a floor rate of
1.0%
) plus
7.5%
per annum.
The Company elect
ed
a LIBOR
rate based on various tenors
, and
wa
s
incurring interest based on an underlying
three-month LIBOR
rate
, which was last elected in
July 2016
.
Restrictive covenants
The Company’s Credit Facility and Term Loan contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at
September 30, 2016
.
Subsequent
e
vents
On October 3, 2016, the Company closed
the sale
of
$400,000
aggregate principal amount of
6.125%
senior unsecured notes due 2024 (the “
S
enior
Notes
”) at an issue price of
100%
of the aggregate principal amount of the
Senior
Notes. The Notes will mature on
October 1, 2024
, unless redeemed in accordance with their terms prior to such date. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$391,
270
. The
Senior
Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. Interest on the
Senior
Notes is payable semi-annually.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
On October 1
1
, 2016, the Term Loan was repaid in full
at the prepayment rate of
101%
using proceeds from the
sale of the
Senior
Notes,
which is expected to
result in a loss on early extinguishment of debt of
$1
2,851
(inclusive of
$3,000
in prepayment fees and
$9,851
of unamortized debt issuance costs).
Note 6 - Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, puts, calls and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument;
see
Note 7
for additional information
regarding fair value.
The Company executes commodity derivative con
tracts under master agreements with
netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
Financial statement presentation and settlements
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets.
See
Note 7
for additional information regarding fair value.
Derivatives not designated as hedging instruments
The Company records its derivative contracts at fair value in the consolidated balance sheet
s
and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement
s
of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement
s
of operations.
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Presentation
|
|
Asset Fair Value
|
|
Liability Fair Value
|
|
Net Derivative Fair Value
|
Commodity
|
|
Classification
|
|
Line Description
|
|
09/30/2016
|
|
12/31/2015
|
|
09/30/2016
|
|
12/31/2015
|
|
09/30/2016
|
|
12/31/2015
|
Natural gas
|
|
Current
|
|
Fair value of derivatives
|
|
$
|
29
|
|
$
|
—
|
|
$
|
(233)
|
|
$
|
—
|
|
$
|
(204)
|
|
$
|
—
|
Natural gas
|
|
Non-current
|
|
Fair value of derivatives
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
Oil
|
|
Current
|
|
Fair value of derivatives
|
|
|
3,473
|
|
|
19,943
|
|
|
(7,553)
|
|
|
—
|
|
|
(4,080)
|
|
|
19,943
|
Oil
|
|
Non-current
|
|
Fair value of derivatives
|
|
|
54
|
|
|
—
|
|
|
(2,936)
|
|
|
—
|
|
|
(2,882)
|
|
|
—
|
|
|
Totals
|
|
|
|
$
|
3,559
|
|
$
|
19,943
|
|
$
|
(10,722)
|
|
$
|
—
|
|
$
|
(7,163)
|
|
$
|
19,943
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
As previously discusse
d, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
|
Presented without
|
|
|
|
As Presented with
|
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
|
$
|
3,591
|
|
$
|
(89)
|
|
$
|
3,502
|
Long-term assets: Fair value of derivatives
|
|
|
57
|
|
|
—
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
|
|
(7,875)
|
|
|
89
|
|
|
(7,786)
|
Long-term liabilities: Fair value of derivatives
|
|
$
|
(2,936)
|
|
$
|
—
|
|
$
|
(2,936)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
Presented without
|
|
|
|
As Presented with
|
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
|
$
|
19,943
|
|
$
|
—
|
|
$
|
19,943
|
For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
4,252
|
|
$
|
9,399
|
|
$
|
15,467
|
|
$
|
23,863
|
Net gain (loss) on fair value adjustments
|
|
|
699
|
|
|
13,758
|
|
|
(26,904)
|
|
|
(6,787)
|
Total gain (loss)
|
|
$
|
4,951
|
|
$
|
23,157
|
|
$
|
(11,437)
|
|
$
|
17,076
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
(161)
|
|
$
|
390
|
|
$
|
357
|
|
$
|
1,235
|
Net gain (loss) on fair value adjustments
|
|
|
345
|
|
|
(264)
|
|
|
(201)
|
|
|
(848)
|
Total gain
|
|
$
|
184
|
|
$
|
126
|
|
$
|
156
|
|
$
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivative contracts
|
|
$
|
5,135
|
|
$
|
23,283
|
|
$
|
(11,281)
|
|
$
|
17,463
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of
September 30, 2016
:
|
|
|
|
|
|
|
|
|
For the Remainder of
|
|
For the Full Year of
|
Oil contracts
|
|
2016
|
|
2017
|
Swap contracts (WTI)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
184
|
|
|
—
|
Weighted average price per Bbl
|
|
$
|
58.23
|
|
$
|
—
|
Swap contracts combined with short puts (WTI, enhanced swaps)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
—
|
|
|
730
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Swap
|
|
$
|
—
|
|
$
|
44.50
|
Short put option
|
|
$
|
—
|
|
$
|
30.00
|
Collar contracts combined with short puts (WTI, three-way collars)
|
|
|
|
|
|
|
Volume (MBbls)
|
|
|
184
|
|
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
65.00
|
|
$
|
—
|
Floor (long put option)
|
|
$
|
55.00
|
|
$
|
—
|
Short put option
|
|
$
|
40.33
|
|
$
|
—
|
Collar contracts (WTI, two-way collars)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
184
|
|
|
438
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
|
$
|
46.50
|
|
$
|
59.05
|
Floor (long put)
|
|
$
|
37.50
|
|
$
|
47.50
|
Call option contracts (short position)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
—
|
|
|
670
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Call strike price
|
|
$
|
—
|
|
$
|
50.00
|
Swap contracts (Midland basis differentials)
|
|
|
|
|
|
|
Volume (MBbls)
|
|
|
368
|
|
|
—
|
Weighted average price per Bbl
|
|
$
|
0.17
|
|
$
|
—
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
|
|
|
|
|
Swap contracts (Henry Hub)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
552
|
|
|
—
|
Weighted average price per MMBtu
|
|
$
|
2.52
|
|
$
|
—
|
Collar contracts combined with short puts (Henry Hub, three-way collars)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
—
|
|
|
1,460
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
—
|
|
$
|
3.71
|
Floor (long put option)
|
|
$
|
—
|
|
$
|
3.00
|
Short put option
|
|
$
|
—
|
|
$
|
2.50
|
Subsequent event
The following derivative contract was executed subsequent to
September 30, 2016
:
|
|
|
|
|
|
|
|
|
For the Remainder of
|
|
For the Remainder of
|
Oil contracts
|
|
2016
|
|
2017
|
Collar contracts (WTI, two-way collars)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
—
|
|
|
1,095
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
—
|
|
$
|
57.79
|
Floor (long put option)
|
|
$
|
—
|
|
$
|
47.50
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
Note 7 - Fair Value Measurements
The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair value of financial instruments
Cash, cash equivalents, and restricted investments.
The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt.
The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.
Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments.
The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts.
See
Note 6
for additional information regarding the Company’s derivative instruments.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
Classification
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
$
|
—
|
|
$
|
3,559
|
|
$
|
—
|
|
$
|
3,559
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
|
—
|
|
|
(10,722)
|
|
|
—
|
|
|
(10,722)
|
Total net assets
|
|
|
|
$
|
—
|
|
$
|
(7,163)
|
|
$
|
—
|
|
$
|
(7,163)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
Classification
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
$
|
—
|
|
$
|
19,943
|
|
$
|
—
|
|
$
|
19,943
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
Total net assets
|
|
|
|
$
|
—
|
|
$
|
19,943
|
|
$
|
—
|
|
$
|
19,943
|
Assets and liabilities measured at fair value on a nonrecurring basis
Acquisition
s
.
As discussed in Note 3, the Company completed
four
acquisition
s
during the
nine
months ended
September 30, 2016
. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and
natural
gas forward prices. The fair value measurements were based on
L
evel 2 and
L
evel
3 inputs.
Note 8 - Income Taxes
The Company 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. As a result of the write-down of oil and natural gas proper
ties in the latter part of 2015
and first half of 2016
,
the Company incurred a cumulative
three
year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was
$139,633
as of
September 30, 2016
.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
Note 9 - Asset Retirement Obligations
The table below summarizes the Company’s asset retirement obligations activity for the
nine months ended September 30, 2016
:
|
|
|
|
Asset retirement obligations at January 1, 2016
|
|
$
|
5,107
|
Accretion expense
|
|
|
762
|
Liabilities incurred
|
|
|
12
|
Liabilities settled
|
|
|
(807)
|
Revisions to estimate
|
|
|
389
|
Asset retirement obligations at end of period
|
|
|
5,463
|
Less: Current asset retirement obligations
|
|
|
(3,529)
|
Long-term asset retirement obligations at September 30, 2016
|
|
$
|
1,934
|
Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at
September 30, 2016
as long-term restricted investments were
$3,329
. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedica
ted to pay future abandonment costs.
Note 10 - Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of
10.0%
per annum of the
$50.00
liquidation preference per share (equivalent to
$5.00
per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were
$1,824
an
d
$1,974
f
or
the three months ended
September 30, 2016
and
2015
,
respectively
, and
$5,471
and
$5,921
for the
nine months ended
September 30, 2016
and
2015
,
respectively
.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share
in cash
, plus any accrued and unpaid dividends to the redemption date.
Following a change of control
in which the Company or the acquirer no longer have a class of common securities listed on a national exchange
, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon
such
change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on
September 30, 2016
, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $
15.70
as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately
3.2
shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.
On
February 4
, 2016
,
the Company exchanged
a total of
120,000
shares of Preferred Stock
f
or
719,000
shares of common stock.
As of
September 30, 2016
, the Company had
1,458,948
shares
of its Preferred Stock issued and outstanding.
Common
s
tock
On March
9
, 2016, the Company completed an underwritten public offering of
15,250,000
shares of its common stock
for total
net proceeds
(after the underwriting discounts and estimated offering costs)
of approximately
$
94,973
.
Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.
On April 25, 2016, the Company completed an underwritten public offering of
25,300,000
shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately
$
205,869
. Proceeds from the offering were used to fund the
May
2016
Big Star Transaction and AMI Transaction,
described in Note 3.
On May 26, 2016, the Company issued
9,333,333
shares of common stock to
partially fund the Big Star Transaction, described in
Note 3
,
at an assumed offering price of
$
11.74
per share, which is the last reported sale price of our common stock on the New York Stock Exchange on
that date
.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(
All
dollar amounts in thousands, except per
share and per
unit data)
|
Table of Contents
|
|
|
|
On September 6, 2016, the Company
completed an underwritten public offering of
29,900,000
shares of
its
common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately
$
421,923
. Proceeds from the offering
were used
to substantially fund the
Plymouth Transaction
, described in Note 3
.
Note 11 - Other
Operating leases
As of
September 30, 2016
, the Company had contracts for
two
horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”).
The
contract
terms of
the
Cactus 1 Rig and Cactus 2 Rig
will
end in July 2018 and August 2018, respectively.
The rig lease agreements include early termination provisions that obligate the Company to
pay
reduced minimum rentals for the
remaining
term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another l
essee.
In January 2016, the Company place
d
its Cactus 1 Rig on standby and
wa
s required to pay a “standby” day
rate of $
15,000
per day, pursuant
to the terms of the agreement
,
a
llowing
the Company
to
retain the option to return the rig to service
under the contract terms
.
In August 2016, the Company returned its Cactus 1 Rig to service.
Subsequent event
In October 2016 the Company entered into a contract for a horizontal drilling rig (the “Cactus 3 Rig”). The contract term will begin
January 2017
through
June 2017
with a day rate of
$16,000
per day.
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
ebsite address is
www.callon.com
. All of our filings with the SEC are available free of charge through our
w
ebsite as soon as reasonably practicable after we file them wit
h, or furnish them to, the SEC. Information on our
w
ebsite 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 swaps.
Our production was approximately
77%
oil and
23%
natural gas for the
nine months ended
September 30, 2016
. On
September 30, 2016
, our
net
acreage position in the Permian Basin was approximatel
y
34,199
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 t
o
$48.70
on
October 28, 2016
. For the three months ended
September 30, 2016
, the average NYMEX price for a barrel of oil was
$44.94
per Bbl compared to
$46.41
per Bbl for the same period of
2015
. The NYMEX price for a barrel of oil ranged from a low of
$39.51
per Bbl to a high of
$48.99
per Bbl for the three months ended
September 30, 2016
.
For the three months ended
September 30, 2016
, the average NYMEX price for natural gas was
$2.81
per MMBtu compared to
$2.77
per MMBtu for the same period in
2015
. The NYMEX price for natural gas ranged from a low of
$2.55
per MMBtu to a high of
$3.06
per MMBtu for the three months ended
September 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
September 30, 2016
, the
realized
prices used in determining the estimated future net cash flows from proved reserves were
$38.92
per barrel of oil and
$2.53
per Mcf of natural gas
(including the value of NGLs in the natural gas stream)
.
For the three months ended September 30, 2016
,
no write-down of oil and natural gas properties was recognized as a result of the cei
ling test limitation.
For the
nine
months
ended
September 30, 2016
, the Company recognized a write-down of oil and natural gas properties
of
$95.8
million
as a result of the ceiling test limitation.
If commodity prices
were to
decline
, we
could
incur additional ceiling test write-downs in the future. However, we do not expect such prevailing commodity prices to have significant adverse effects on our proved oil and gas reserves. See
Note 2
in the Footnotes to the Financial Statements for more information.
The table below presents
the cumulative
results of the full cost ceiling test
for 2016
as of
September 30, 2016
, along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of
September 30, 2016
,
and accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to
September 30, 2016
that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12-Month Average Realized Prices
|
|
Excess (Deficit) of
full cost ceiling over net capitalized costs
|
|
(Increase) Decrease in excess of full cost ceiling over net capitalized costs
|
Pricing Scenarios
|
|
Oil ($/Bbl)
|
|
Natural gas ($/Mcf)
|
|
(in thousands)
|
September 30, 2016 Actual
|
|
$
|
38.92
|
|
$
|
2.53
|
|
$
|
46,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas +10%
|
|
$
|
42.81
|
|
$
|
2.78
|
|
$
|
180,877
|
|
$
|
134,410
|
Oil and natural gas -10%
|
|
|
35.02
|
|
|
2.27
|
|
|
(87,943)
|
|
|
(134,410)
|
Oil price sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil +10%
|
|
$
|
42.81
|
|
$
|
2.53
|
|
$
|
166,734
|
|
$
|
120,267
|
Oil -10%
|
|
|
35.02
|
|
|
2.53
|
|
|
(73,800)
|
|
|
(120,267)
|
Natural gas sensitivity
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas +10%
|
|
$
|
38.92
|
|
$
|
2.78
|
|
$
|
60,610
|
|
$
|
14,143
|
Natural gas -10%
|
|
|
38.92
|
|
|
2.27
|
|
|
32,324
|
|
|
(14,143)
|
Operational Highlights
Our production
grew
70%
a
nd
53%
for
the three
and
nine
months ended
September 30, 2016
,
respectively,
compared to the same period
s
of
2015
,
in
creasing to
1,527
MBOE from
896
MBOE
and
3,884
MBOE from
2,533
MBOE
for the comparative three
and
nine
month period
s, respectively
.
For
the three months ended
September 30, 2016
,
we drill
ed
eight g
ross (
5.4
net) horizontal wells
and
completed
11
gross (
6.8
net) horizontal wells. For the
nine
months ended
September 30, 2016
, we drilled
19
gross (
13.4
net) horizontal wells and completed
25
gross (
17.3
net) horizontal wells. As of
September 30, 2016
, we had
three g
ross (
2.8
net)
horizontal wells awaiting completion.
As of
September 30, 2016
,
we h
ad
419
gross (
335
net) working interest oil wells,
three g
ross (
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 natura
l 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
the first nine months of
2016,
we completed
four
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
s
. As of
September 30, 2016
, there was
no
balance outstanding on the Credit Facility
, which has a
borrowing base
of
$3
85
million.
Subsequent to the third quarter of 2016, we completed one debt offering, the proceeds of which were used to repay amounts borrowed under our Term Loan and for general corporate purposes.
For the
nine months ended September 30, 2016
, cash and cash equivalents
in
crease
d
$324.7
million to
$325.9
million compared to
$1.2
million
at
December 31, 2015
.
As of October 28, 2016, our cash and cash equivalents balance w
as
$100.8
mi
llion following the closing of the Plymouth Transaction, offering of Senior Notes and repayment of the Term Loan.
Liquidity and cash flow
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
(dollars in millions)
|
|
2016
|
|
2015
|
Net cash provided by operating activities
|
|
$
|
49.9
|
|
$
|
55.5
|
Net cash used in investing activities
|
|
|
(401.8)
|
|
|
(178.2)
|
Net cash provided by financing activities
|
|
|
676.6
|
|
|
123.6
|
Net change in cash
|
|
$
|
324.7
|
|
$
|
0.9
|
Operating
activities.
For the
nine months ended September 30, 2016
, net cash
provided by o
perating activities wa
s
$49.9
mi
llion compared to
net cash provided by operating activities of
$55.5
million for the same period in
2015
. The change was predominantly attributable to the following:
|
·
|
|
A
n
increase in revenue offset by
a
decrease
on settlement
s
of derivative cont
racts
;
|
|
·
|
|
An increase in certain operating expenses related to
acquired properties;
|
|
·
|
|
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;
|
|
·
|
|
A payment of a secured deposit related to
the Plymouth Transaction
that closed subsequent to September 30, 2016;
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
nine months ended September 30, 2016
, net cash used in investing activities was
$401.8
million compared to
$178.2
million for the same period in
2015
. The
$223.6
million
in
crease in cash used in investing
activities was primarily attributable to the following:
|
·
|
|
A
$67.5
millio
n 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
the transition back to a two-rig program in August 2016
;
a
nd
|
|
·
|
|
A
$276.6
million increase
in
acquisitions, net of proceeds from the sale of mineral interest and equipm
ent, during the
nine months ended
months
September 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 millions):
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
|
2016
|
|
2015
|
|
|
$ Change
|
Operational expenditures
|
|
$
|
90.5
|
|
$
|
158.0
|
|
$
|
(67.5)
|
Seismic and other
|
|
|
10.0
|
|
|
1.8
|
|
|
8.2
|
Capitalized general and administrative costs
|
|
|
9.0
|
|
|
7.9
|
|
|
1.1
|
Capitalized interest
|
|
|
13.1
|
|
|
8.0
|
|
|
5.1
|
Total capital expenditures (a)
|
|
|
122.6
|
|
|
175.7
|
|
|
(53.1)
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
|
302.1
|
|
|
2.8
|
|
|
299.3
|
Proceeds from the sale of mineral interest and equipment
|
|
|
(22.9)
|
|
|
(0.3)
|
|
|
(22.6)
|
Total investing activities
|
|
$
|
401.8
|
|
$
|
178.2
|
|
$
|
223.6
|
|
(a)
|
|
On an accrual (GAAP) basis, the
metho
dology used for establishing our annual capital budget, operational expenditures for the
nine
months ended
September 30, 2
016
were
$99.3
million. Inclusive of
capitalized general and administrative and interest costs, total
capital
expenditures were
$136.8
million.
|
General and administrative expe
nses 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 C
redit Facility, term debt and equity offerings.
For the
nine months ended September 30, 2016
, net cash provided by financing
activities was
$676.6
million compared to cash provided by financing activities of
$123.6
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
w
ere
$40 million
,
$104
million less than the same period of 2015; and
|
|
·
|
|
A
$657.2
million increase in proceeds resulting from common stock offering
s
in March
,
April
, and September
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
Third
Quarter Summary
In early
August
201
6, we
a
nnounced an increase of
our op
erational capital guidance
to $
14
0
mi
llion. The increased 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
future program
development
plans
in this area
.
Operational capital expenditures on an accrual basis
were
$99.3
million for the
nine
months ended
September 30, 2016
.
In addition to the operational capital expenditures,
$15.1
million of capitalized general and administrative
and
$13.2
million of
capitalized interest
expenses were accrued in the
nine
months ended
September 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 s
ufficient to fund our remaining 2016 capital program, including working capital requirements.
Results of Operations
The following table sets forth certai
n operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
% Change
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,153
|
|
|
689
|
|
|
464
|
|
67%
|
Natural gas (MMcf)
|
|
|
2,244
|
|
|
1,239
|
|
|
1,005
|
|
81%
|
Total (MBOE)
|
|
|
1,527
|
|
|
896
|
|
|
631
|
|
70%
|
Average daily production (BOE/d)
|
|
|
16,598
|
|
|
9,739
|
|
|
6,859
|
|
70%
|
% oil (BOE basis)
|
|
|
76%
|
|
|
77%
|
|
|
|
|
|
Average realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
42.58
|
|
$
|
44.39
|
|
$
|
(1.81)
|
|
(4)%
|
Oil (Bbl) (including impact of cash settled derivatives)
|
|
|
46.27
|
|
|
58.03
|
|
|
(11.76)
|
|
(20)%
|
Natural gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
3.04
|
|
$
|
3.01
|
|
$
|
0.03
|
|
1%
|
Natural gas (Mcf) (including impact of cash settled derivatives)
|
|
|
2.97
|
|
|
3.33
|
|
|
(0.36)
|
|
(11)%
|
Total (BOE) (excluding impact of cash settled derivatives)
|
|
$
|
36.63
|
|
$
|
38.30
|
|
$
|
(1.67)
|
|
(4)%
|
Total (BOE) (including impact of cash settled derivatives)
|
|
|
39.30
|
|
|
49.22
|
|
|
(9.92)
|
|
(20)%
|
Oil and natural gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
49,095
|
|
$
|
30,582
|
|
$
|
18,513
|
|
61%
|
Natural gas revenue
|
|
|
6,832
|
|
|
3,734
|
|
|
3,098
|
|
83%
|
Total
|
|
$
|
55,927
|
|
$
|
34,316
|
|
$
|
21,611
|
|
63%
|
Additional per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
Sales price (excluding impact of cash settled derivatives)
|
|
$
|
36.63
|
|
$
|
38.30
|
|
$
|
(1.67)
|
|
(4)%
|
Lease operating expense
|
|
|
6.52
|
|
|
8.03
|
|
|
(1.51)
|
|
(19)%
|
Production taxes
|
|
|
2.28
|
|
|
2.88
|
|
|
(0.60)
|
|
(21)%
|
Operating margin
|
|
$
|
27.83
|
|
$
|
27.39
|
|
$
|
0.44
|
|
2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
% Change
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
2,993
|
|
|
2,012
|
|
|
981
|
|
49%
|
Natural gas (MMcf)
|
|
|
5,345
|
|
|
3,124
|
|
|
2,221
|
|
71%
|
Total (MBOE)
|
|
|
3,884
|
|
|
2,533
|
|
|
1,351
|
|
53%
|
Average daily production (BOE/d)
|
|
|
14,175
|
|
|
9,278
|
|
|
4,897
|
|
53%
|
% oil (BOE basis)
|
|
|
77%
|
|
|
79%
|
|
|
|
|
|
Average realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
39.12
|
|
$
|
47.01
|
|
$
|
(7.89)
|
|
(17)%
|
Oil (Bbl) (including impact of cash settled derivatives)
|
|
|
44.29
|
|
|
58.87
|
|
|
(14.58)
|
|
(25)%
|
Natural gas (Mcf) (excluding impact of cash settled derivatives)
|
|
$
|
2.75
|
|
$
|
3.00
|
|
$
|
(0.25)
|
|
(8)%
|
Natural gas (Mcf) (including impact of cash settled derivatives)
|
|
|
2.81
|
|
|
3.39
|
|
|
(0.58)
|
|
(17)%
|
Total (BOE) (excluding impact of cash settled derivatives)
|
|
$
|
33.93
|
|
$
|
41.04
|
|
$
|
(7.11)
|
|
(17)%
|
Total (BOE) (including impact of cash settled derivatives)
|
|
|
38.00
|
|
|
50.95
|
|
|
(12.95)
|
|
(25)%
|
Oil and natural gas revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
117,093
|
|
$
|
94,584
|
|
$
|
22,509
|
|
24%
|
Natural gas revenue
|
|
|
14,677
|
|
|
9,365
|
|
|
5,312
|
|
57%
|
Total
|
|
$
|
131,770
|
|
$
|
103,949
|
|
$
|
27,821
|
|
27%
|
Additional per BOE data:
|
|
|
|
|
|
|
|
|
|
|
|
Sales price (excluding impact of cash settled derivatives)
|
|
$
|
33.93
|
|
$
|
41.04
|
|
$
|
(7.11)
|
|
(17)%
|
Lease operating expense
|
|
|
6.24
|
|
|
8.18
|
|
|
(1.94)
|
|
(24)%
|
Production taxes
|
|
|
2.10
|
|
|
3.08
|
|
|
(0.98)
|
|
(32)%
|
Operating margin
|
|
$
|
25.59
|
|
$
|
29.78
|
|
$
|
(4.19)
|
|
(14)%
|
Revenues
The following t
able reconcile
s
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 September 30, 2015
|
|
$
|
30,582
|
|
$
|
3,734
|
|
$
|
34,316
|
Volume increase
|
|
|
20,597
|
|
|
3,025
|
|
|
23,622
|
Price increase (decrease)
|
|
|
(2,084)
|
|
|
73
|
|
|
(2,011)
|
Net increase
|
|
|
18,513
|
|
|
3,098
|
|
|
21,611
|
Revenues for the three months ended September 30, 2016
|
|
$
|
49,095
|
|
$
|
6,832
|
|
$
|
55,927
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oil
|
|
Natural Gas
|
|
Total
|
Revenues for the nine months ended September 30, 2015
|
|
$
|
94,584
|
|
$
|
9,365
|
|
$
|
103,949
|
Volume increase
|
|
|
46,117
|
|
|
6,663
|
|
|
52,780
|
Price decrease
|
|
|
(23,608)
|
|
|
(1,351)
|
|
|
(24,959)
|
Net increase
|
|
|
22,509
|
|
|
5,312
|
|
|
27,821
|
Revenues for the nine months ended September 30, 2016
|
|
$
|
117,093
|
|
$
|
14,677
|
|
$
|
131,770
|
Oil revenue
For the quarter ended
September 30, 2016
, oil revenues of
$49.1
million
in
creased
$18.5
million, or
61%
, compared to revenues of
$30.6
million for the same period of
2015
.
T
he
in
crease
in oil revenue was
primarily attributable to a
67%
increase in production offset by a
4%
decrease in the average realized sales price
, which fell to
$42.58
per Bbl from
$44.39
per Bbl
.
The increase in production was comprised of
353
MBbls attributable to wells placed on production as a result of our horizontal drilling program and
307
MBbls attributable to producing wells
added
from our acquired properties. Offsetting these increases were normal
and
expected declines from our existing wells.
For the
nine months ended
September 30, 2016
, oil revenues of
$117.1
million
in
creased
$22.5
million, or
24%
, compared to revenues of
$94.6
million for the same period of
2015
. The
in
crease in oil revenue was primarily attributable to
a
49%
increase in production, and was predominantly offset by
a
17%
decrease in the average realized sales price, which fell to
$39.12
per Bbl from
$47.01
per Bbl.
The increase in production was comprised of
979
MBbls attributable to wells placed on production as a result of our horizontal drilling program and
397
MBbls attributable to producing wells
added
from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells
.
See
Note 3
in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Natural gas revenue (including NGLs)
Natural gas revenues of
$6.8
million
in
creased
$3.1
million, or
83%
, during the
three months ended
September 30, 2016
,
compared to
$3.7
million for the same period of
2015
. The
in
crease primarily relates to
a
81%
increase in natural gas volumes
, while the
average
realized
price
was consistent at
$3.04
per Mcf
as compared to
$3.01
per Mcf
for the prior comparative quarter of 2015
, reflecting
both natural gas and natural gas liquids prices
.
The increase in production was comprised of
529
MMcf attributable to wells placed on production as a result of our horizont
al drilling program and
452
M
Mcf
attributable to producing wells
added
from our acquired properties. Offsetting these increases were and normal expected declines from our existing wells.
Natural gas revenues of
$14.7
million increased
$5.3
million, or
57%
, during the
nine months ended
,
September 30, 2016
,
compared to
$9.4
million for the same period of
2015
. The increase primarily relates to a
71%
increase in natural gas volumes and was predominantly offset by a
n
8%
decrease in the average price realized, which fell to
$2.75
per Mcf from
$3.00
per Mcf, reflecting decreases in both natural gas and natural gas liquids prices.
The increase in production was comprised of
1,252
MMcf attributable to wells placed on production as a result of our horizont
al drilling program and
622
MMcf attributable to producing wells
added
from our acquired properties.
Offsetting these increases were normal and expected declines from our existing wells.
See
Note 3
in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
O
perating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Three Months Ended September 30,
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
|
|
2016
|
|
BOE
|
|
2015
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
9,961
|
|
$
|
6.52
|
|
$
|
7,194
|
|
$
|
8.03
|
|
$
|
2,767
|
|
38%
|
|
$
|
(1.51)
|
|
(19)%
|
Production taxes
|
|
|
3,478
|
|
|
2.28
|
|
|
2,583
|
|
|
2.88
|
|
|
895
|
|
35%
|
|
|
(0.60)
|
|
(21)%
|
Depreciation, depletion and amortization
|
|
|
17,303
|
|
|
11.33
|
|
|
16,704
|
|
|
18.64
|
|
|
599
|
|
4%
|
|
|
(7.31)
|
|
(39)%
|
General and administrative
|
|
|
7,891
|
|
|
5.17
|
|
|
4,302
|
|
|
4.80
|
|
|
3,589
|
|
83%
|
|
|
0.37
|
|
8%
|
Accretion expense
|
|
|
187
|
|
|
0.12
|
|
|
142
|
|
|
0.16
|
|
|
45
|
|
32%
|
|
|
(0.04)
|
|
(25)%
|
Acquisition expense
|
|
|
456
|
|
|
nm
|
|
|
—
|
|
|
nm
|
|
|
456
|
|
nm
|
|
|
nm
|
|
nm
|
Write-down of oil and natural gas properties
|
|
|
—
|
|
|
nm
|
|
|
87,301
|
|
|
nm
|
|
|
(87,301)
|
|
nm
|
|
|
nm
|
|
nm
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
|
|
2016
|
|
BOE
|
|
2015
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
24,229
|
|
$
|
6.24
|
|
$
|
20,728
|
|
$
|
8.18
|
|
$
|
3,501
|
|
17%
|
|
$
|
(1.94)
|
|
(24)%
|
Production taxes
|
|
|
8,153
|
|
|
2.10
|
|
|
7,800
|
|
|
3.08
|
|
|
353
|
|
5%
|
|
|
(0.98)
|
|
(32)%
|
Depreciation, depletion and amortization
|
|
|
49,318
|
|
|
12.70
|
|
|
52,395
|
|
|
20.68
|
|
|
(3,077)
|
|
(6)%
|
|
|
(7.98)
|
|
(39)%
|
General and administrative
|
|
|
19,755
|
|
|
5.09
|
|
|
22,167
|
|
|
8.75
|
|
|
(2,412)
|
|
(11)%
|
|
|
(3.66)
|
|
(42)%
|
Accretion expense
|
|
|
762
|
|
|
0.20
|
|
|
485
|
|
|
0.19
|
|
|
277
|
|
57%
|
|
|
0.01
|
|
5%
|
Write-down of oil and natural gas properties
|
|
|
95,788
|
|
|
nm
|
|
|
87,301
|
|
|
nm
|
|
|
8,487
|
|
nm
|
|
|
nm
|
|
nm
|
Rig termination fee
|
|
|
—
|
|
|
nm
|
|
|
3,641
|
|
|
nm
|
|
|
(3,641)
|
|
nm
|
|
|
nm
|
|
nm
|
Acquisition expense
|
|
|
2,410
|
|
|
nm
|
|
|
—
|
|
|
nm
|
|
|
2,410
|
|
nm
|
|
|
nm
|
|
nm
|
nm = not meaningful
Lease operating expenses.
These are daily costs incurred to extract oil and natural gas, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs
, gas treating fees
and workover expenses related to our oil and natural gas properties.
For the
three months ended
September 30, 2016
,
LOE
in
creased by
38%
to
$10.0
million
compared to
$7.2
million for
the same period of
2015
.
Contributing to the increase for the current quarter was
$3.0
million related to
oil and natural gas
properties acquired during the second quarter of 2016 (see
Note 3
in the Footnotes to the Financial Statements).
Excluding LOE related to
these acquired
properties, LOE decreased by
$0.2
million, or
3%
, compared to the same period of 2015.
F
or the
three months ended
September 30, 2016
, LOE per BOE
decreased to
$6.52
per BOE
compared to
$8.03
per BOE for the same period of
2015
,
which was
primarily
attributable
to
improving
operational efficiency and working with our service partners to achieve cost reduction
s
.
Higher production volumes
also
contributed to the
19%
per BOE decrease for the
three months ended
September 30, 2016
.
The increase in production was primarily attributable to an increased number of producing wells
from our horizontal drilling program and acquisitions
as discussed above.
For the
nine months ended
September 30, 2016
, LOE
in
creased by
17%
to
$24.2
million compared to
$20.7
million for
the same period of
2015
.
Contributing to the increase for the current period was
$3.8
million related to
oil and natural gas
properties acquired during the second quarter of 2016 (see
Note 3
in the Footnotes to the Financial Statements).
Excluding LOE related to
these acquired
properties, LOE decreased by
$0.
3
million, or
1
%
, compared to the same period of 2015.
For the
nine months ended
September 30, 2016
, LOE per BOE decreased to
$6.24
per BOE compared to
$8.18
per BOE for the same period of
2015
, which was primarily attributable to
improving
operational efficiency
and
working with our service partners to achieve cost reductions
. Higher production volumes also contributed to the
24%
per BOE decrease for the
nine months ended
September 30, 2016
.
The increase in production was primarily attributable to an increased number of producing wells
from our horizontal drilling program and acquisitions
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
September 30, 2016
in
creased by
35%
to
$3.5
million compared to
$2.6
million for the same period of
2015
. The
in
crease was primarily due to
a
n
in
crease in
severance taxes, which was attributable to the increase in revenue.
The increase was offset by a decrease in
ad valorem taxes
attributable to a lower valuation of our oil and gas properties by the taxing jurisdictions.
On a per BOE basis, production taxes for the
three months ended
September 30, 2016
decreased by
21%
compared to the same period of
2015
.
Production taxes for the
nine months ended
September 30, 2016
in
creased by
5%
to
$8.2
milli
on compared to
$7.8
million for the same period of
2015
. The
in
crease was primarily due to
an increase in severance taxes, which was attributable to the increase in revenue. The increase was offset by a
decrease in ad valorem taxes
attributable to a lower valuation of our oil and gas properties by the taxing jurisdictions.
On a per BOE basis, production taxes for the
nine months ended
September 30, 2016
decreased
b
y
32%
co
mpared to the same period of
20
15.
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
September 30, 2016
,
D
D
&A
in
creased
4%
to
$17.3
mil
lion
compared to
$16.7
million for the same period of
2015
. For the
three months ended
September 30, 2016
,
DD&
A decreased
39%
per BOE to
$11.33
pe
r BOE compared to
$18.64
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 decrease in our depreciable base was primarily related to the write-down of oil and natural gas properties
during
the last half of
2015 and the first half
of 2016, offset by additions made through our horizontal drilling program and acquisitions.
For the
nine months ended
September 30, 2016
, DD&
A decreased
6%
to
$49.3
mil
lion compared to
$52.4
million for the same period of
2015
. For the
nine months ended
September 30, 2016
, D
D&A decreased
39%
per BOE to
$12.70
per BO
E compared to
$20.68
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 decrease in our depreciable base was primarily related to the write-down of oil and natural gas properties during
the last half of
2015
and the first
half
of 2016, offset by additions made through our horizontal drilling program and acquisitions.
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 services, and legal compliance.
G&A for the
three months ended
September 30, 2016
in
creased to $
7.9
mi
llion compared to
$4.3
million for the same period of
2015
.
G&A expenses for the periods indicated include the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended September 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
3.7
|
|
$
|
3.5
|
|
$
|
0.2
|
|
6%
|
Share-based compensation
|
|
|
0.8
|
|
|
0.6
|
|
|
0.2
|
|
33%
|
Fair value adjustments of cash-settled RSU awards
|
|
|
3.4
|
|
|
0.1
|
|
|
3.3
|
|
nm
|
Non-recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
Expense related to a threatened proxy contest
|
|
|
—
|
|
|
0.1
|
|
|
(0.1)
|
|
(100)%
|
Total G&A expenses
|
|
$
|
7.9
|
|
$
|
4.3
|
|
$
|
3.6
|
|
84%
|
nm = not meaningful
G&A for the
nine months ended
September 30, 2016
decreased to
$19.8
mi
llion compared to
$22.2
million for the same period of
2015
.
G&A expenses for the periods indicated include the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
11.6
|
|
$
|
11.2
|
|
$
|
0.4
|
|
4%
|
Share-based compensation
|
|
|
2.0
|
|
|
1.6
|
|
|
0.4
|
|
25%
|
Fair value adjustments of cash-settled RSU awards
|
|
|
6.0
|
|
|
4.3
|
|
|
1.7
|
|
40%
|
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
|
|
|
0.4
|
|
|
(0.2)
|
|
(50)%
|
Total G&A expenses
|
|
$
|
19.8
|
|
$
|
22.2
|
|
$
|
(2.4)
|
|
(11)%
|
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
ARO
in
creased
32%
and
57%
f
or
the
three and nine months ended September 30, 2016
,
respectively,
c
ompared to the same period
s
of
2015
. Accretion expense generally correlates with the Company’s ARO
,
which w
as
$5.5
mill
ion at
September 30, 2016
as compared to
$4.7
million at
September 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 nine months ended September 30, 2016
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).
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 months ended
September 30, 2016
, the Company
did not
recognize
a
write-down of oil and natural gas properties
compared to
a write-down of
$87.3
million for the same period of
2015
as a result of the ceiling test limitation. For the nine months ended September 30, 2016, the Company recognized a write-down of oil and natural gas properties of
$95.8
million
compared to a write-down of $87.3
million
for the same period of
2015
as a result of the ceiling test limitation. See Note
2
in the Footnotes to the Financial Statements for additional inform
ation.
If commodity prices
were to
decline, we could incur additional ceiling test write-downs in the future.
Other Income and Expenses and Preferred Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
$ Change
|
|
% Change
|
Interest expense, net of capitalized amounts
|
|
$
|
831
|
|
$
|
5,603
|
|
$
|
(4,772)
|
|
(85)%
|
Gain on derivative contracts
|
|
|
(5,135)
|
|
|
(23,283)
|
|
|
18,148
|
|
(78)%
|
Other income, net
|
|
|
(122)
|
|
|
(92)
|
|
|
(30)
|
|
33%
|
Total
|
|
$
|
(4,426)
|
|
$
|
(17,772)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense
|
|
$
|
(62)
|
|
$
|
45,667
|
|
$
|
(45,729)
|
|
(100)%
|
Preferred stock dividends
|
|
|
(1,824)
|
|
|
(1,974)
|
|
|
150
|
|
(8)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
$ Change
|
|
% Change
|
Interest expense, net of capitalized amounts
|
|
$
|
10,502
|
|
$
|
15,567
|
|
$
|
(5,065)
|
|
(33)%
|
(Gain) loss on derivative contracts
|
|
|
11,281
|
|
|
(17,463)
|
|
|
28,744
|
|
(165)%
|
Other income, net
|
|
|
(299)
|
|
|
(177)
|
|
|
(122)
|
|
69%
|
Total
|
|
$
|
21,484
|
|
$
|
(2,073)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense
|
|
$
|
(62)
|
|
$
|
38,474
|
|
$
|
(38,536)
|
|
(100)%
|
Preferred stock dividends
|
|
|
(5,471)
|
|
|
(5,921)
|
|
|
450
|
|
(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,
incurre
d during the
three months ended
September 30, 2016
de
creased
$4.8
million compared to the same period of
2015
. The
de
crease is
primarily attributable to
a
$4.8
mi
llion increase in capitalized interest compared to the 2015 period, resulting from a higher average unevaluated property balance for the
three months ended
September 30, 2016
as compared to the same period of 2015.
The increase in unevaluated property was prima
rily due to acquired properties
.
Interest expense
, net of capitalized amounts,
incurred during
the
nine months ended
September 30, 2016
de
creased
$5.1
million compared to the same period of
2015
. The
de
crease is primarily attributable to a
$5.2
million
in
crease in capitalized interest compared to the
2015
period, resulting from a
high
er average unevaluated property balance for the
nine months ended
September 30, 2016
as compared to the same period of
2015
.
The increase in unevaluated property was primarily due to
acquired properties
.
Offsetting
the
de
crease was a
$0.1
million
in
crease in interest expense relate
d to our debt.
Se
e
Notes 3
and
5
i
n the Footnotes to the Financial Statements for additional information on our
acquisitions and
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.
For the
three months ended
September 30, 2016
, the
net
gain
on
derivative contracts
was
$5.1
million
compared to a
$23.2
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 September 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
4.2
|
|
$
|
9.4
|
|
$
|
(5.2)
|
Net gain on fair value adjustments
|
|
|
0.7
|
|
|
13.7
|
|
|
(13.0)
|
Total gain
|
|
$
|
4.9
|
|
$
|
23.1
|
|
$
|
(18.2)
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
(0.2)
|
|
$
|
0.4
|
|
$
|
(0.6)
|
Net gain (loss) on fair value adjustments
|
|
|
0.4
|
|
|
(0.3)
|
|
|
0.7
|
Total gain
|
|
$
|
0.2
|
|
$
|
0.1
|
|
$
|
0.1
|
|
|
|
|
|
|
|
|
|
|
Total gain on derivative contracts
|
|
$
|
5.1
|
|
$
|
23.2
|
|
$
|
(18.1)
|
For the
nine months ended
September 30, 2016
, the n
et loss on
derivative contract
s was
$11.2
mil
lion compared to a
$17.4
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 Nine Months Ended September 30,
|
|
|
2016
|
|
2015
|
|
$ Change
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
15.5
|
|
$
|
23.9
|
|
$
|
(8.4)
|
Net loss on fair value adjustments
|
|
|
(26.9)
|
|
|
(6.8)
|
|
|
(20.1)
|
Total gain (loss)
|
|
$
|
(11.4)
|
|
$
|
17.1
|
|
$
|
(28.5)
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
0.4
|
|
$
|
1.2
|
|
$
|
(0.8)
|
Net loss on fair value adjustments
|
|
|
(0.2)
|
|
|
(0.9)
|
|
|
0.7
|
Total gain
|
|
$
|
0.2
|
|
$
|
0.3
|
|
$
|
(0.1)
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivative contracts
|
|
$
|
(11.2)
|
|
$
|
17.4
|
|
$
|
(28.6)
|
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
(benefit)
expense.
The Company had income tax
benefit
of $0.1 million
for the
three and nine months ended September 30, 2016
compared to
an
income tax
expense
of
$45.7
million
and
$38.5
million
for the same period
s
of
2015
. The change in income tax expense is primarily related to recording a valuation allowanc
e
of
$139.6
m
illion
at
September 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 nine months ended September 30, 2016
wer
e
$1.8
million
and
$5.5
million, respectively,
as compared to
$2.0
million
and
$5.9
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
yield
. See
Note 10
in the Footnotes to the Financial Statements
for additional informati
on.