Note 1 - Description of Business and Basis of Presentation
Description of business
Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin in West Texas. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale in the Midland Basin. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, acreage purchases, joint ventures and asset swaps.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.
The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of
Callon Petroleum
Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.
These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended
December 31, 2016
. The balance sheet at
December 31, 2016
has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended
December 31, 2017
.
In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows
for the periods indicated.
Certain prior year amounts
may
have been reclassified to conform to current year presentation.
Recently adopted accounting policies
In March 2016, the FASB issued ASU No. 2016-09,
Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. As of March 31, 2017, the Company adopted this ASU, which did not have a material impact on its financial statements.
The Company has elected to no longer estimate forfeitures.
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Callon Petroleum Company
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Table of Contents
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Note 2 - 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.
201
7
acquisitions
On February 13, 2017, the Company completed the acquisition of
29,175
gross (
16,688
net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of
$632,947
, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see
Note 9
for additional information regarding the equity offering). The Company acquired an
82%
average working interest in the properties acquired in the Ameredev Transaction.
In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of
$46,138
to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016.
The following table summarizes the estimated acquisition date fair values of the acquisition:
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Evaluated oil and natural gas properties
|
|
$
|
134,315
|
Unevaluated oil and natural gas properties
|
|
|
498,800
|
Asset retirement obligations
|
|
|
(168)
|
Net assets acquired
|
|
$
|
632,947
|
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.
2016 acquisitions
On October 20, 2016, the Company completed the acquisition of
6,904
gross (
5,952
net) acres
in the Midland Basin,
primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of
$339,687
, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net
proceeds of an equity offering (see
Note 9
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.
On May 26, 2016, the Company completed the acquisition of
17,298
gross (
14,089
net) acres
in the Midland Basin,
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 (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) for a total purchase price of
$329,573
, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an
81%
average working interest (
61%
average net revenue interest) in the properties acquired in the Big Star Transaction.
Unaudited pro forma financial statements
The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the
Ameredev Transaction, Plymouth Transaction and
Big Star Tr
ansaction
had occurred as presented, or to project the Company’s results of operations for any future periods:
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Three Months Ended March 31,
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2017
(a)
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2016
(a)
|
Revenues
|
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$
|
84,416
|
|
$
|
42,615
|
Income (loss) from operations
|
|
|
34,907
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(35,451)
|
Income (loss) available to common stockholders
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47,963
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(38,908)
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Net income (loss) per common share:
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Basic
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$
|
0.24
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$
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(0.31)
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Diluted
|
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$
|
0.24
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|
$
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(0.31)
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(a)
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The pro forma financial information was prepared assuming
the
Ameredev Transaction
occurred as of January 1, 2016 and the
Plymouth Transaction and Big Star Transaction
occurred as of January 1, 2015.
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Callon Petroleum Company
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Table of Contents
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The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.
The properties associated with the
Ameredev Transaction, Plymouth Transaction and 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.
Subsequent event
In April 2017, the Company entered into an agreement to acquire
7
,0
31
gross (
2,4
8
8
net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of
$52,500
, excluding customary purchase price adjustments. The Company plans to
fund
the cash purchase price with its available cash
and borrowings on our senior secured revolving credit f
acility.
Note 3 - Earnings
Per Share
The following table sets forth the computation of basic and diluted earnings per share:
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(share amounts in thousands)
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Three Months Ended March 31,
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2017
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2016
|
Net income (loss)
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$
|
47,129
|
|
$
|
(41,109)
|
Preferred stock dividends
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(1,824)
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|
(1,824)
|
Income (loss) available to common stockholders
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$
|
45,305
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$
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(42,933)
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Weighted average shares outstanding
|
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201,054
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83,582
|
Dilutive impact of restricted stock
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686
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—
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Weighted average shares outstanding for diluted income (loss) per share
|
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201,740
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83,582
|
|
|
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|
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Basic income (loss) per share
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$
|
0.23
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|
$
|
(0.51)
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Diluted income (loss) per share
|
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$
|
0.22
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|
$
|
(0.51)
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Stock options
(a)
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15
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15
|
Restricted stock
(a)
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—
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25
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(a)
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Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive
.
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Note 4 - Borrowings
The Company’s borrowings consisted of the following at:
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March 31, 2017
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December 31, 2016
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Principal components:
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Senior secured revolving credit facility
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$
|
—
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$
|
—
|
6.125% senior unsecured notes due 2024
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400,000
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400,000
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Total principal outstanding
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400,000
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400,000
|
6.125% senior unsecured notes due 2024, unamortized deferred financing costs
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(9,464)
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(9,781)
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Total carrying value of borrowings
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$
|
390,536
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$
|
390,219
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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 participants 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. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.
Effective November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000, but elected to maintain the borrowing base at $385,000.
As of March 31, 2017, the Company continued to maintain the Credit Facility’s borrowing base at
$385,000
.
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Callon Petroleum Company
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Table of Contents
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As of March 31, 2017, there was
no
balance outstanding on the Credit Facility. For the quarter ended March 31, 2017, the Credit Facility had a weighted-average interest rate of
2.83%
, 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.
6.125% senior notes due 2024 (“6.125% Senior Notes”)
On October 3, 2016, the Company issued
$400,000
aggregate principal amount of
6.125%
Senior Notes with a maturity date of
October 1, 2024
and interest payable semi-annually beginning on
April 1, 2017
. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$391,270
. The 6.125% 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. The subsidiary guarantor is
100%
owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) prior to October 1, 2019, a redemption of up to
35%
of the principal in an amount not greater than the net proceeds from certain equity offerings, and within
180
days of the closing date of such equity offerings, at a redemption price of
106.125%
of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least
65%
of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of
100%
of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of
104.594%
of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of
103.063%
of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of
101.531%
of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of
100%
of principal if the redemption occurs on or after October 1, 2022.
Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of
101%
of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
Restrictive covenants
The Company’s Credit Facility and
the indenture governing our 6.125% Senior Notes
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 March 31, 2017.
Note 5 - 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, p
ut and
call
options
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 6
for additional information
regarding fair value.
The Company executes commodity derivative contracts 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.
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Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Table of Contents
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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 6
for additional information regarding fair value.
Deri
vatives not designated as hedging instruments
The C
ompany records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statements of operations.
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
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Balance Sheet Presentation
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Asset Fair Value
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Liability Fair Value
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Net Derivative Fair Value
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Commodity
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Classification
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Line Description
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03/31/2017
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12/31/2016
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03/31/2017
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12/31/2016
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03/31/2017
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12/31/2016
|
Natural gas
|
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Current
|
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Fair value of derivatives
|
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$
|
—
|
|
$
|
—
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$
|
(64)
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$
|
(593)
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$
|
(64)
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$
|
(593)
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Oil
|
|
Current
|
|
Fair value of derivatives
|
|
|
3,093
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|
|
103
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(6,366)
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|
(17,675)
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(3,273)
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(17,572)
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Oil
|
|
Non-current
|
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Fair value of derivatives
|
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2,939
|
|
|
—
|
|
|
—
|
|
|
(28)
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2,939
|
|
|
(28)
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|
Totals
|
|
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|
$
|
6,032
|
|
$
|
103
|
|
$
|
(6,430)
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|
$
|
(18,296)
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$
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(398)
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|
$
|
(18,193)
|
As previously discussed, 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:
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March 31, 2017
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Presented without
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As Presented with
|
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Effects of Netting
|
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Effects of Netting
|
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Effects of Netting
|
Current assets: Fair value of derivatives
|
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$
|
5,055
|
|
$
|
(1,962)
|
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$
|
3,093
|
Long-term assets: Fair value of derivatives
|
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|
2,939
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|
|
—
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|
2,939
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Current liabilities: Fair value of derivatives
|
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$
|
(8,392)
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$
|
1,962
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$
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(6,430)
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|
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|
|
|
|
|
|
|
|
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|
December 31, 2016
|
|
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Presented without
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As Presented with
|
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Effects of Netting
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Effects of Netting
|
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Effects of Netting
|
Current assets: Fair value of derivatives
|
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$
|
1,836
|
|
$
|
(1,733)
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|
$
|
103
|
|
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|
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Current liabilities: Fair value of derivatives
|
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$
|
(20,001)
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|
$
|
1,733
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$
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(18,268)
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Long-term liabilities: Fair value of derivatives
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(28)
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—
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(28)
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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:
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Three Months Ended March 31,
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2017
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2016
|
Oil derivatives
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|
|
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|
|
Net gain (loss) on settlements
|
|
$
|
(2,524)
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$
|
7,507
|
Net gain (loss) on fair value adjustments
|
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|
17,266
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|
|
(9,137)
|
Total gain (loss) on oil derivatives
|
|
$
|
14,742
|
|
$
|
(1,630)
|
Natural gas derivatives
|
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|
|
|
|
|
Net gain on settlements
|
|
$
|
33
|
|
$
|
209
|
Net gain on fair value adjustments
|
|
|
528
|
|
|
489
|
Total gain on natural gas derivatives
|
|
$
|
561
|
|
$
|
698
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|
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Total gain (loss) on oil & natural gas derivatives
|
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$
|
15,303
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|
$
|
(932)
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Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Table of Contents
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Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of
March 31, 2017
:
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For the Remainder of
|
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For the Full Year of
|
Oil contracts
|
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2017
|
|
2018
|
Swap contracts combined with short puts (WTI, enhanced swaps)
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Total volume (MBbls)
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|
550
|
|
|
—
|
Weighted average price per Bbl
|
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|
|
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|
Swap
|
|
$
|
44.50
|
|
$
|
—
|
Short put option
|
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$
|
30.00
|
|
$
|
—
|
Deferred premium put option
|
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|
|
|
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|
Total volume (MBbls)
|
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|
250
|
|
|
—
|
Premium per Bbl
|
|
$
|
2.05
|
|
$
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Long put option
|
|
$
|
50.00
|
|
$
|
—
|
Deferred premium put spread option
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
506
|
|
|
—
|
Premium per Bbl
|
|
$
|
2.45
|
|
$
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Long put option
|
|
$
|
50.00
|
|
$
|
—
|
Short put option
|
|
$
|
40.00
|
|
$
|
—
|
Collar contracts (WTI, two-way collars)
|
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|
|
|
|
|
Total volume (MBbls)
|
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|
1,018
|
|
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
|
$
|
58.19
|
|
$
|
—
|
Floor (long put)
|
|
$
|
47.50
|
|
$
|
—
|
Call option contracts (short position)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
505
|
|
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Call strike price
|
|
$
|
50.00
|
|
$
|
—
|
Swap contracts (Midland basis differential)
|
|
|
|
|
|
|
Volume (MBbls)
|
|
|
1,650
|
|
|
2,008
|
Weighted average price per Bbl
|
|
$
|
(0.52)
|
|
$
|
(1.02)
|
Collar contracts combined with short puts (WTI, three-way collars)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
—
|
|
|
2,738
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
—
|
|
$
|
62.84
|
Floor (long put option)
|
|
$
|
—
|
|
$
|
50.00
|
Short put option
|
|
$
|
—
|
|
$
|
40.00
|
|
|
|
|
|
|
|
|
|
For the Remainder of
|
|
For the Full Year of
|
Natural gas contracts
|
|
2017
|
|
2018
|
Collar contracts combined with short puts (Henry Hub, three-way collars)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
1,100
|
|
|
—
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
3.71
|
|
$
|
—
|
Floor (long put option)
|
|
$
|
3.00
|
|
$
|
—
|
Short put option
|
|
$
|
2.50
|
|
$
|
—
|
Collar contracts (Henry Hub, two-way collars)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
1,100
|
|
|
—
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
3.68
|
|
$
|
—
|
Floor (long put option)
|
|
$
|
3.00
|
|
$
|
—
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
Table of Contents
|
|
|
|
Subsequent event
The following derivative contract
s
w
ere
executed subsequent to
March 31, 2017
:
|
|
|
|
|
|
|
|
|
For the Remainder of
|
|
For the Full Year of
|
Gas contracts
|
|
2017
|
|
2018
|
Collar contracts (Henry Hub, two-way collars)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
488
|
|
|
720
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call option)
|
|
$
|
3.84
|
|
$
|
3.84
|
Floor (long put option)
|
|
$
|
3.40
|
|
$
|
3.40
|
Swap contracts
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
736
|
|
|
—
|
Weighted average price per MMBtu
|
|
$
|
3.39
|
|
$
|
—
|
Note 6 - 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 v
alue of
financial i
nstruments
Cash, cash equivalents, and restricted investments.
The carrying amounts for these instruments approximated 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
Credit Facility
(a)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
6.125% Senior Notes
(b)
|
|
|
390,536
|
|
|
416,000
|
|
|
390,219
|
|
|
412,000
|
Total
|
|
$
|
390,536
|
|
$
|
416,000
|
|
$
|
390,219
|
|
$
|
412,000
|
|
(b)
|
|
The
fair value was based upon Level 2 inputs. See
Note 4
for additional information about the Company’s 6.125% Senior Notes.
|
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 5
for additional information regarding the Company’s derivative instruments.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
Table of Contents
|
|
|
|
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
Classification
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
$
|
—
|
|
$
|
6,032
|
|
$
|
—
|
|
$
|
6,032
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
|
—
|
|
|
(6,430)
|
|
|
—
|
|
|
(6,430)
|
Total net liabilities
|
|
|
|
$
|
—
|
|
$
|
(398)
|
|
$
|
—
|
|
$
|
(398)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
Classification
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
$
|
—
|
|
$
|
103
|
|
$
|
—
|
|
$
|
103
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
|
—
|
|
|
(18,296)
|
|
|
—
|
|
|
(18,296)
|
Total net liabilities
|
|
|
|
$
|
—
|
|
$
|
(18,193)
|
|
$
|
—
|
|
$
|
(18,193)
|
Assets and
l
iabilities
m
easured at
f
air
v
alue on a
n
onrecurring
b
asis
Acquisitions.
The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs.
Note 7 - 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 the first half of 2016
,
the Company
has
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
full
valuation allowance
for a
ll of
the deferred tax asset.
The valuation allowance was
$127,073
as of
March 31, 2017
.
The Company adopted a new accounting standard that simplified
the accounting for stock-based
compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017, and therefore, the net effect of this new accounting standard was
zero. See Note 1 for additional information about this new accounting standard.
Note 8 - Asset Retirement Obligations
The table below summarizes the
activity for
the
Company’s asset retirement obligations
:
|
|
|
|
|
|
For the Three Months Ended
|
|
|
March 31, 2017
|
Asset retirement obligations at January 1, 2017
|
|
$
|
6,661
|
Accretion expense
|
|
|
184
|
Liabilities incurred
|
|
|
195
|
Liabilities settled
|
|
|
(88)
|
Revisions to estimate
|
|
|
(712)
|
Asset retirement obligations at end of period
|
|
|
6,240
|
Less: Current asset retirement obligations
|
|
|
(1,588)
|
Long-term asset retirement obligations at March 31, 2017
|
|
$
|
4,652
|
Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the
C
onsolidated
B
alance
S
heet
s
at
March 31, 2017
as long-term restricted investments were
$3,339
. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs
for several of the Company’s oil and natural gas properties.
|
|
|
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 - 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
f
or
the three months ended
March 31, 2017
and
2016
.
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, 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
March 31, 2017
, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $
13.16
as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately
3.8
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
March
31, 2017
, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
Common
s
tock
On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,917. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described
in Note 2.
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 $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described
in Note 2.
On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in
Note 2
, 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.
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 Big Star Transaction, described
in Note 2
, and other working interest acquisitions.
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 $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.
Note 10 - Other
Operating leases
As of
March 31, 2017
, the Company had contracts for
t
hree
horizontal drilling rigs
(the “Cactus 1 Rig”, “Cactus 2 Rig” and “Cactus 3 Rig”). The contract terms, as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The contract terms of the Cactus 3 Rig
, that commenced drilling in mid-January 2017,
will end in July 2017.
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.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
Table of Contents
|
|
|
|
Subsequent event
In April 2017 the Company entered into a contract for a
fourth
horizontal drilling rig. The contract term will begin July 2017 through July
2019 with a day rate of $18,000 per day.