Note 1
- Description of Busi
ness 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
F
ootnotes to the
Financial S
tatements are presented in thousands, except for per share and per unit data.
The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC
also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.
All intercompany accounts and transactions have been eliminated.
In the opinion of management, the accompanying audited 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.
Note 2
– Summary
of Significant Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
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B.
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Cash and Cash Equivalents
|
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts receivable consists primarily of accrued oil and natural gas production receivables
and joint interest receivables from outside working interest owners
.
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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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D.
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Revenue Recognition and Natural Gas Balancing
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The Company recognizes revenue under the entitlement
s
method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables
and payables
were
immaterial as
of
December 31,
2016
and
2015
.
See the Accounting Standards Updates (“ASU”) section within this footnote for information about recently issued ASUs related to Revenue Recognition.
The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended:
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For the Year Ended December 31,
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2016
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2015
|
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2014
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Enterprise Crude Oil, LLC
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43%
|
|
42%
|
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51%
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Shell Trading Company
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18%
|
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4%
|
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—
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Plains Marketing, L.P.
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16%
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19%
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22%
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Permian Transport and Trading
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—
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15%
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7%
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Sunoco
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—
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9%
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10%
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Other
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23%
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11%
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10%
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Total
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100%
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100%
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100%
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Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.
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F.
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Oil and Natural Gas Properties
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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.
When applicable, proceeds from the sale o
r disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs
through adjustments to accumulated
depreciation,
depletion
, amortization and impairment
unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which ca
se a gain or
loss is recognized
.
Historical and estimated future development costs of oil and natural gas properties
,
which have been evaluated and contain proved reserves, as well as the historical cost of properties
that
have been determined to have no future economic value,
are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or
the Company
determines that these costs have been impaired.
The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves.
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 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
December 31
, 2016
and
2015
,
the average realized prices used in determining the estimated future net cash flows from proved reserves were
$42.75
and
$50.16
per barrel of oil
, respectively,
and
$2.48
and
$2.64
per Mcf of natural gas
, respectively
.
For the period
s
ended
December 31, 2016
and
2015
,
the Company recognized a write-down of oil and natural gas properties of
$95,788
and
$208,435
, respectively,
as a result of the ceiling test limitation.
See
Notes 2
and
13
f
or additional information regarding the Company’s oil and natural gas properties.
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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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Upon the acquisition or discovery
of oil and natural gas properties, the Company estimates the future net costs to
dismantle
,
abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full
cost pool when the related liabilities are incurred. In accordance with
full cost accounting
rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part o
f the costs subject to the full
cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full
cost ceiling amount.
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G.
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Other Property and Equipment
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The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of
three
to
20
years. Depreciation expense of
$793
,
$865
and
$836
relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended
December 31, 2016
,
2015
and
2014
, respectively. The accumulated depreciation on other property and equipment was
$15,227
and
$14,719
as of
December 31, 2016
and
2015
, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See
Note 14
for addition
al information.
The Company capitalizes interest on unevaluated
oil and gas
properties. Capitalized interest cannot exceed gross interest expense. During the years ended
December 31, 2016
,
2015
and
2014
, the Company capitalized
$19,857
,
$10,459
and
$4,295
of interest expense.
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I.
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Deferred
F
inancing
C
osts
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Deferred financing costs are stated at cost, net of amortization,
and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, d
eferred financing costs are stated at cost, net of amortization,
as an asset on the balance sheet.
Amortization of deferred financing costs
is computed using the straight-line method over the life of the loan
.
Amortization of deferred
financing
costs of
$3,115
,
$3,123
and
$1,272
w
ere
recorded for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
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J.
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Asset Retirement Obligations
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The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See
Note 12
for additional information.
Derivative contracts outstanding as of
December 31, 2016
were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See
Notes 6
and
7
for additional information regarding the Company’s derivative contracts.
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward
s
and tax credit carryforwards. A valuation allowance is provided for that portion
of deferred tax assets
, if any, for which it is deemed more likely than not that it will not be realized.
As of
December 31, 201
6
the valuation allowance was
$140,192
.
See
Note 11
for additional information.
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M.
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Share-Based Compensation
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The Company grants to directors and employees stock options
and
restricted stock awards (“RS awards”)
.
The Company also grants
restricted stock unit awards (“
RSU awards
”)
that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”).
Stock Options.
For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally
three
years).
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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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RS awards, RSU
equity
awards and Cash-settleable RSU awards.
For RS and RSU
equity
awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally
three
years).
For RSU equity awards with vesting subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years).
For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expe
nse is based on the fair value
measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated
fair
value recognized over the vesting period (generally
three
years).
See the Accounting Standards Updates section within this footnote for information about recently issued ASUs related to Stock Compensation.
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N.
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Non-cash Investing and Supplemental
Cash Flow Information
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The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated:
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For the Years Ended December 31,
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2016
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2015
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2014
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Non-cash investing information:
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Change in accrued capital expenditures
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$
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(613)
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$
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(16,813)
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$
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12,850
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Supplemental cash flow information
(a)
:
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Cash paid for interest, net of capitalized interest
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$
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8,679
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$
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17,978
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$
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2,988
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(a)
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During the three year period ended
2016
, the Company paid no federal income taxes.
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O.
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Earnings per Share (
“
EPS
”
)
|
The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and
RSUs
settleable in shares.
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P.
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Accounting Standards Updates (“ASU”)
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Recently Issued ASUs
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers
(“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective.
In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period
.
The Company is currently evaluating the impact of
the
standard; however, we do not believe th
e
standard will have a material impact on our financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-08,
Revenue from Contracts with Customers – Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption or modified retrospective adoption.
The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In April 2016, the FASB issued ASU No. 2016-10,
Revenue from Contracts with Customers – Identifying Performance Obligations and Licensing
. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance.
This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted.
The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In May 2016, the FASB
issued
ASU No.
2016-12,
Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients
. This update applies only to the following areas from Accounting Standards Codification Topic 606:
assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected
from customers, non-cash consideration, contract modification at transition, completed contracts at transition and
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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)
|
Table of Contents
|
technical correction.
This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted.
The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (T
opic 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 coupon 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 interests 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.
In February 2016, the FASB issued ASU No. 2016-02,
Leases (Topic 842)
(“ASU 2016-02”). The standard requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
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.
The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures.
In December 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topics 230): Restricted Cash
(“ASU 2016-18”).
The objecti
ve
of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures.
Recently Adopted ASUs
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. As of December 31, 2016, the Company adopted this ASU, which did not have a material impact on its financial stat
ements.
Note 3 – Acquisitions and Dispositio
ns
2016 acquisitions
On October 20, 2016, the Company completed the acquisition of
6,904
gross (
5,952
net) acres 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
$339,687
, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an
82%
average working interest (
62%
average net revenue interest) in the properties acquired in the Plymouth Transaction.
The following table summarizes the estimated acquisition date
fair values of the net assets
acquired in the acquisition:
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Evaluated oil and natural gas properties
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$
|
65,043
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Unevaluated oil and natural gas properties
|
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274,664
|
Asset retirement obligations
|
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(20)
|
Net assets acquired
|
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$
|
339,687
|
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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)
|
Table of Contents
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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
(
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 dat
e)
for a total purchase price of
$329,573
, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an
81%
average working interest (
61%
average net revenue interest) in the properties acquired in the Big Star Transaction.
The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
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Evaluated oil and natural gas properties
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$
|
96,194
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Unevaluated oil and natural gas properties
|
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233,387
|
Asset retirement obligations
|
|
|
(8)
|
Net assets acquired
|
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$
|
329,573
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The preliminary purchase price allocation
s
are
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.
During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately
$73,240
, net of
$23,045
in sales of working interest.
The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area.
2015 acquisitions
During 2015, the Company closed on
an
acquisition in the Midland Basin for an aggregate total purchase price of approximately
$
29,800
. The acquisition included
the
purchase of
additional
working interest
in
the Company’s
existing core
operating
area
.
2014 acquisitions
On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “
Central Midland Basin
Transaction
”)
for an aggregate cash purchase price of
$210,205
based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a
62%
working interest (
46.5%
net revenue interest) in the
Central Midland Basin
Transaction
. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of
$122,450
and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see
Notes 5
and
10
, respectively.
The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:
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|
|
Evaluated oil and natural gas properties
|
|
$
|
91,895
|
Unevaluated oil and natural gas properties
|
|
|
118,450
|
Asset retirement obligations
|
|
|
(140)
|
Net assets acquired
|
|
$
|
210,205
|
During 2014, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately
$8,200
. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area.
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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)
|
Table of Contents
|
Unaudited
p
ro 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 Big Star Transaction, Plymouth Transaction and Central Midland Basin Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:
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|
|
|
|
|
|
|
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|
Twelve Months Ended December 31,
|
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|
2016
(a)
|
|
2015
(a)
|
|
2014
(b)
|
Revenues
|
|
$
|
225,326
|
|
$
|
168,506
|
|
$
|
180,458
|
Income (loss) from operations
|
|
|
(41,094)
|
|
|
(131,435)
|
|
|
53,526
|
Income (loss) available to common stockholders
|
|
|
(85,240)
|
|
|
(153,735)
|
|
|
33,674
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.68)
|
|
$
|
(1.18)
|
|
$
|
0.57
|
Diluted
|
|
$
|
(0.68)
|
|
$
|
(1.18)
|
|
$
|
0.56
|
|
(a)
|
|
The pro forma financial information was prepared assuming the Big Star Transaction and Plymouth Transaction occurred as of January 1, 2015.
|
|
(b)
|
|
The pro forma financial information was prepared assuming the Central Midland Basin Transaction occurred as of January 1, 2013.
|
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 Big Star Transaction, the Plymouth Transaction and the Central Midland Basin 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
On
Februa
ry 13
,
2017
, the Company completed the acquisi
tion of
27,552
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
$633,000
, 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 10
for additional information regarding the equity offering). The Company acquired a
n
82%
ave
rage working interest
(
75%
avera
ge net revenue 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.
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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)
|
Table of Contents
|
Note 4
- Ear
nings Per Share
Basic earnings (loss) per share is computed by dividing income
(loss)
available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock
method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
Net income (loss)
|
|
$
|
(91,813)
|
|
$
|
(240,139)
|
|
$
|
37,766
|
Preferred stock dividends
|
|
|
(7,295)
|
|
|
(7,895)
|
|
|
(7,895)
|
Income (loss) available to common stockholders
|
|
$
|
(99,108)
|
|
$
|
(248,034)
|
|
$
|
29,871
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
126,258
|
|
|
65,708
|
|
|
44,848
|
Dilutive impact of restricted stock
|
|
|
—
|
|
|
—
|
|
|
1,113
|
Weighted average shares outstanding for diluted income (loss) per share
(a)
|
|
|
126,258
|
|
|
65,708
|
|
|
45,961
|
|
|
|
|
|
|
|
|
|
|
Basic income (loss) per share
|
|
$
|
(0.78)
|
|
$
|
(3.77)
|
|
$
|
0.67
|
Diluted income (loss) per share
|
|
$
|
(0.78)
|
|
$
|
(3.77)
|
|
$
|
0.65
|
|
|
|
|
|
|
|
Stock options
(b)
|
|
|
15
|
|
|
15
|
|
|
30
|
Restricted stock
(b)
|
|
|
—
|
|
|
126
|
|
|
317
|
|
(a)
|
|
Because the Company reported a loss
available to common stockholders
for the year
s
ended
December 31, 2016
,
and 2015,
no unvested stock awards were included in computing loss per share because the effect was anti-dilutive.
|
|
(b)
|
|
Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutiv
e.
|
Note 5
– Borr
owings
The Company’s borrowings consisted of the following at:
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Principal components:
|
|
|
|
|
|
|
Senior secured revolving credit facility
|
|
$
|
—
|
|
$
|
40,000
|
Secured second lien term loan
|
|
|
—
|
|
|
300,000
|
6.125% senior unsecured notes due 2024
|
|
|
400,000
|
|
|
—
|
Total principal outstanding
|
|
|
400,000
|
|
|
340,000
|
Secured second lien term loan, unamortized deferred financing costs
|
|
|
—
|
|
|
(11,435)
|
6.125% senior unsecured notes due 2024, unamortized deferred financing costs
|
|
|
(9,781)
|
|
|
—
|
Total carrying value of borrowings
|
|
$
|
390,219
|
|
$
|
328,565
|
C
redit
F
acility
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
n
t
s
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 July 13, 2016,
the Credit Facility’s borrowing base was increased to
$385,000
and the Company’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.
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
December 31, 2016
, the Credit Facility’s borrowing base remained at
$385,000
.
|
|
|
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 of
December 31, 2016
, the
re was
no
balance outstanding on the Credit Facility
. For the year ended December 31, 2016, the Credit Facility had a
weighted-average interest rate of
2.60%
, 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.
Term loans
On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to
$125,000
, including initial commitments of
$100,000
and additional availability of
$25,000
subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of
September 11, 2019
, and was not subject to mandatory prepayments unless new debt or preferred stock
wa
s issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i)
102%
if the prepayment event occur
red
prior to March 11, 2015, and (ii)
101%
if the prepayment event occur
red
on or after March 15, 2015 but before March 15, 2016, and (iii)
100%
for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement
.
On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the
Central Midland
A
cquisition, resulting in a loss on early extinguishment of debt of
$3,054
.
The Second Lien Loan has a maturity date of
October 8, 2021
.
The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. Borrowings under the Second Lien Loan were subject to interest, calculated at a rate of LIBOR (subject to a floor rate of
1.0%
) plus
7.5%
per annum.
The Company elected a LIBOR rate based on various tenors, and was incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016.
The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount
w
as
(i)
102%
of principal if the prepayment event occurred
prior to October 8, 201
6
, and (ii)
101%
of principal
if the prepayment event occur
red
on or after October 8, 201
6
but before October 8, 201
7
, and (iii)
100%
of principal
for prepayments made on or after October 8, 201
7
.
The Second Lien Loan
wa
s secured by junior liens on properties mor
tgaged under the Credit Facility, subject to an intercreditor agreement.
On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of debt of $
12,883
(inclusive of
$3,000
in prepayment fees and
$9,883
of unamortized debt issuance costs).
6.125% senior notes due 2024 (“
6.125%
Senior Notes”)
On October 3, 2016, the Company
issued
$400,000
aggregate principa
l amount of
6.125%
Senior Notes
with
a maturity date of
October 1, 2024
and i
nterest 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 Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) p
rior 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) p
rior to October 1, 2019,
a
redem
ption 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.
13% senior notes due 2016 (“
13%
Senior Notes”) and deferred credit
On April 11, 2014, the Company completed a full redemption of the remaining
$48,481
principal amount of outstanding
13%
Senior Notes using proceeds from the Second Lien Loan. The redemption resulted in a net
$3,205
gain on the early extinguishment of debt (including
$4,780
of accelerated deferred credit amortization). The gain represents the difference between the
$50,057
paid for the redemption of the
13%
Senior Notes (
$1,576
of redemption costs, primarily the call premium) and the carrying value of the remaining
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
13%
Senior Notes of
$53,261
(inclusive of
$4,780
of deferred credit). The Company also paid
$193
in accrued interest through the redemption date. Upon the redemption, the indenture governing the
13%
Senior Notes was discharged in accordance with its terms.
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
December 31, 2016
.
Note 6
- Der
ivative 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, put
and
call
option
s 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 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.
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 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Presentation
|
|
Asset Fair Value
|
|
Liability Fair Value
|
|
Net Derivative Fair Value
|
Commodity
|
|
Classification
|
|
Line Description
|
|
12/31/2016
|
|
12/31/2015
|
|
12/31/2016
|
|
12/31/2015
|
|
12/31/2016
|
|
12/31/2015
|
Natural gas
|
|
Current
|
|
Fair value of derivatives
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(593)
|
|
$
|
—
|
|
$
|
(593)
|
|
$
|
—
|
Oil
|
|
Current
|
|
Fair value of derivatives
|
|
|
103
|
|
|
19,943
|
|
|
(17,675)
|
|
|
—
|
|
|
(17,572)
|
|
|
19,943
|
Oil
|
|
Non-current
|
|
Fair value of derivatives
|
|
|
—
|
|
|
—
|
|
|
(28)
|
|
|
—
|
|
|
(28)
|
|
|
—
|
|
|
Total
|
|
|
|
$
|
103
|
|
$
|
19,943
|
|
$
|
(18,296)
|
|
$
|
—
|
|
$
|
(18,193)
|
|
$
|
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 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:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2016
|
|
|
Presented without
|
|
|
|
As Presented with
|
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
|
$
|
1,836
|
|
$
|
(1,733)
|
|
$
|
103
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
|
|
(20,001)
|
|
|
1,733
|
|
|
(18,268)
|
Long-term liabilities: Fair value of derivatives
|
|
$
|
(28)
|
|
$
|
—
|
|
$
|
(28)
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended 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:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
102
|
|
$
|
1,717
|
|
$
|
(84)
|
Net gain (loss) on fair value adjustments
|
|
|
(593)
|
|
|
(1,255)
|
|
|
1,267
|
Total gain (loss)
|
|
$
|
(491)
|
|
$
|
462
|
|
$
|
1,183
|
Oil derivatives
|
|
|
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
17,801
|
|
$
|
33,299
|
|
$
|
4,170
|
Net gain (loss) on fair value adjustments
|
|
|
(37,543)
|
|
|
(5,403)
|
|
|
26,383
|
Total gain (loss)
|
|
$
|
(19,742)
|
|
$
|
27,896
|
|
$
|
30,553
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivative contracts
|
|
$
|
(20,233)
|
|
$
|
28,358
|
|
$
|
31,736
|
|
|
|
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
December 31, 2016
:
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
For the Full Year of
|
Oil contracts
|
|
2017
|
|
2018
|
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
|
|
$
|
—
|
Deferred premium put option
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
498
|
|
|
—
|
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)
|
|
|
|
|
|
|
Total volume (MBbls)
|
|
|
1,351
|
|
|
—
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
|
$
|
58.19
|
|
$
|
—
|
Floor (long put)
|
|
$
|
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 differential)
|
|
|
|
|
|
|
Volume (MBbls)
|
|
|
2,004
|
|
|
1,825
|
Weighted average price per Bbl
|
|
$
|
(0.52)
|
|
$
|
(1.02)
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
|
|
|
|
|
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
|
|
$
|
—
|
Collar contracts (Henry Hub, two-way collars)
|
|
|
|
|
|
|
Total volume (BBtu)
|
|
|
1,460
|
|
|
—
|
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 December 31, 2016:
|
|
|
|
|
|
|
|
|
For the Remainder of
|
|
For the Remainder of
|
Oil contracts
|
|
2017
|
|
2018
|
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
|
Note 7 - Fair Valu
e 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
Credit Facility
(a)
|
|
$
|
—
|
|
$
|
—
|
|
$
|
40,000
|
|
$
|
40,000
|
Second Lien
(a)
|
|
|
—
|
|
|
—
|
|
|
288,565
|
|
|
288,565
|
6.125% Senior Notes
(b)
|
|
|
390,219
|
|
|
412,000
|
|
|
—
|
|
|
—
|
Total
|
|
$
|
390,219
|
|
$
|
412,000
|
|
$
|
328,565
|
|
$
|
328,565
|
|
(a)
|
|
F
loating
-
rate debt
.
|
|
(b)
|
|
The fair value
was based upon
Level 2 inputs
.
See Note 5 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 6
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 assets
|
|
|
|
$
|
—
|
|
$
|
(18,193)
|
|
$
|
—
|
|
$
|
(18,193)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Acquisitions.
The Company determine
s
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 8 – Emplo
yee Benefit Plans
The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in
Note 9
. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
Savings and Protection Plan
The Savings and Protection Plan (“401
(k)
Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company
c
ommon
s
tock to employees. The amounts held under the 401
(k)
Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401
(k)
Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were
$1,018
,
$999
and
$1,017
in the years
2016
,
2015
and
2014
, respectively.
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance
2,300,000
shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional
841,000
shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to
3,141,000
at the inception of the plan. Another provision provided that shares
,
which would otherwise become available for issu
ance
under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan.
At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the Company’s common stock available for grant under the Plan by
2,000,000
shares from
2,300,000
shares to
4,300,000
shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is
5,141,000
as of the effective date of the First Amendment.
As of
December 31, 2016
, the 2011 Plan had
2,270,448
shares remaining and eligible for future issuance.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
RSU e
quity
a
wards
.
RSU e
quity awards
issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events.
RSU e
quity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards.
For market-based
RSU equity
awards, the Company recognizes expense based on
the fair value of the awards at the grant date
. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded.
Market-based RSU equity awards
that vest
are
based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded.
Cash-
s
ettled RSU
a
wards.
Certain of the Company’s RSUs awarded require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded.
The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group.
Note 9 - Shar
e-Based Compensation
As discussed in
Note 8
, the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At
December 31, 2016
, shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were
2,270,448
.
The following table presents share-based compensation expense for each respective period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
Share-based compensation cost for:
|
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
RSU equity awards
|
|
$
|
4,536
|
|
$
|
—
|
|
$
|
3,797
|
|
$
|
—
|
|
$
|
4,223
|
|
$
|
—
|
Cash-settleable RSU awards
|
|
|
—
|
|
|
12,285
|
|
|
—
|
|
|
11,437
|
|
|
—
|
|
|
6,918
|
401(k) contributions in shares
|
|
|
277
|
|
|
—
|
|
|
266
|
|
|
—
|
|
|
270
|
|
|
—
|
Total share-based compensation cost
(a)
|
|
$
|
4,813
|
|
$
|
12,285
|
|
$
|
4,063
|
|
$
|
11,437
|
|
$
|
4,493
|
|
$
|
6,918
|
|
(a)
|
|
The portion of this share-based compensation cost that was included in general and administrative expense totaled
$9,722
,
$9,299
and
$7,235
for the same years, respectively, and the portion capitalized to oil and gas properties was
$7,376,
$6,201
and
$4,176
, respectively.
|
The following table presents the unrecognized compensation cost for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Unrecognized compensation cost related to:
|
|
2016
|
|
2015
|
|
2014
|
Unvested RSU equity awards
|
|
$
|
7,276
|
|
$
|
5,208
|
|
$
|
3,979
|
Unvested cash-settleable RSU awards
|
|
|
8,948
|
|
|
4,728
|
|
|
4,977
|
The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of
2
years
.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
|
|
|
|
|
|
|
|
December 31,
|
Consolidated Balance Sheets Classification
|
|
2016
|
|
2015
|
Cash-settled RSU awards (current)
|
|
$
|
8,919
|
|
$
|
10,128
|
Cash-settled RSU awards (non-current)
|
|
|
8,071
|
|
|
4,877
|
Total cash-settled RSU awards
|
|
$
|
16,990
|
|
$
|
15,005
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
Stock Options
The Company issued
no
stock options for the past
three
years and had
no
options vest or
forfeit
during
2016
. Additionally,
no
options were exercised, and
no
options expired unexercised during the year. As of
December 31, 2016
, the Company had
15,000
options outstanding and
exercisable
at a weighted average exercise price per option of
$14.37
, with
no
aggregate intrinsic value and with a weighted-average remaining contract life per unit of
0.3
years.
As of
December 31, 2015
, the Company had
15,000
options outstanding and
exercisable
at a weighted average exercise price per option of
$14.37
, with
no
aggregate intrinsic value and with a weighted-average remaining contract life per unit of
1.3
years.
As of December 31, 201
4
, the Company had
30,000
options outstanding and
exercisable
at a weighted average exercise price per option of
$14.04
, with
no
aggregate intrinsic value and with a weighted-average remaining contract life per unit of
1.3
years.
Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
|
(shares in 000s)
|
|
Number of Shares
|
|
|
Grant-Date Fair Value per Share
|
|
Period over which expense is expected to be recognized
|
Outstanding at the beginning of the period
|
|
1,416
|
|
$
|
6.94
|
|
|
Granted
(a)
|
|
684
|
|
|
12.63
|
|
|
Vested
(b)
|
|
(630)
|
|
|
4.14
|
|
|
Forfeited
|
|
(22)
|
|
|
9.56
|
|
|
Outstanding at the end of the period
|
|
1,448
|
|
$
|
10.81
|
|
1.6
|
|
(a)
|
|
Includes
143
market-based RSUs that will vest at a range of
0%
-
200%
. See
Note 8
for additional information about market-based RSU equity awards.
|
|
(b)
|
|
The fair value of shares vest
ed was
$2,608
.
|
For the year ended
December 31, 2015
, the Company granted
559,556
RSUs with a weighted average grant-date fair value of
$8.98
per share. The fair value of shares vested during
2015
was
$5,425
. For the year ended December 31,
2014
, the Company granted
333,468
RSUs with a weighted average grant-date fair value of
$9.67
per share. The fair value of shares vested during
2014
was
$4,338
.
As of
December 31, 2016
, the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition):
|
|
|
|
|
|
|
(shares in 000s)
|
|
Base Units Outstanding
|
|
Potential Minimum Units Vesting
|
|
Potential Maximum Units Vesting
|
Vesting in 2017
|
|
227
|
|
19
|
|
435
|
Vesting in 2018
|
|
244
|
|
25
|
|
464
|
Vesting in 2019
|
|
29
|
|
29
|
|
29
|
Other
|
|
191
|
|
191
|
|
191
|
Total cash-settleable RSUs
|
|
691
|
|
264
|
|
1,119
|
For the year ended
December 31, 2016
,
281,792
market-based cash-settled RSUs subject to the peer market-based vesting described in
Note 8
vested at
200%
of their issued units
, resulting in payable amounts of
$8,662
in
2017
. Also during
2016
,
45,282
non-market-based cash settled RSUs vested, resulting in cash payments of
$493
in
2016
. During
2015
,
853,673
market-based cash-settled RSUs subject to the peer market-based vesting described above vested at between
150%
-
200%
of their issued units, depending on the date of the vesting, resulting in cash payments of
$3,319
in
2015
and
$9,807
in
2016
. Also during
2015
,
72,108
non-market-based cash
settled RSUs vested, resulting in cash payments of
$545
in
2015
. See
Note 8
for additional information regarding cash-settleable RSUs.
Note 10
– Eq
uity 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
$7,295
,
$7,895
and
$7,895
in
2016
,
2015
and
2014
respectively.
|
|
|
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 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
December 31, 2016
,
and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of
$
15.37
as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately
3
.
3
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
for
719,000
shares of
c
ommon
s
tock.
As of
December 31, 2016
, the Company had
1,458,948
shares
of its Preferred Stock issued and outstanding.
Common Stock
On December 1
9
, 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 3
.
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 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.
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 3
, 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.
On November
16
, 2015, the Company completed an underwritten public offering of
12,000,000
shares of its common stock at
$
8.40
per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase
1,800,000
additional shares of common stock at
$8.40
per share, before underwriting discounts. The Company received net proceeds of approximately
$109,864
, after the underwriting discounts and estimated offering costs
, which were used to repay amounts outstanding under the Credit Facility
.
On March 13, 2015, the Company completed an underwritten public offering of
9,000,000
shares of its common stock at
$
6.55
per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase
1,350,000
additional shares of common stock at
$6.55
per share, before underwriting discounts. The Company received net proceeds of approximately
$65,595
, after the underwriting discounts and estimated offering costs
, which were used to repay amounts outstanding under the Credit Facility.
On September 15, 2014 the Company completed an underwritten public offering of
12,500,000
shares of its common stock at
$9.00
per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase
1,875,000
additional shares of common stock at
$9.00
per share. The Company received net proceeds of approximately
$122,450
, after the underwriting discounts and estimated offering costs, which were used to fund a portion of the purchase price of the
Central Midland Basin
Transaction
, described in
Note 3
.
|
|
|
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 11
- Inco
me Taxes
The following table presents Callon’s
deferred tax assets and liabilities with respect
to its
carryforwards
and other temporary differences:
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2016
|
|
2015
|
Deferred tax asset
|
|
|
|
|
|
|
Federal net operating loss carryforward
(a)
|
|
$
|
135,711
|
|
$
|
107,935
|
Statutory depletion carryforward
|
|
|
8,843
|
|
|
8,843
|
Alternative minimum tax credit carryforward
|
|
|
104
|
|
|
208
|
Asset retirement obligations
|
|
|
1,181
|
|
|
630
|
Derivatives
|
|
|
6,456
|
|
|
—
|
Unvested RSU equity awards
|
|
|
2,092
|
|
|
1,418
|
Other
|
|
|
4,376
|
|
|
6,823
|
Deferred tax asset before valuation allowance
|
|
|
158,763
|
|
|
125,857
|
Deferred tax liability
|
|
|
|
|
|
|
Oil and natural gas properties
|
|
|
18,661
|
|
|
6,488
|
Derivatives
|
|
|
—
|
|
|
6,984
|
Other
|
|
|
—
|
|
|
3,542
|
Total deferred tax liability
|
|
|
18,661
|
|
|
17,014
|
Net deferred tax asset before valuation allowance
|
|
|
140,102
|
|
|
108,843
|
Less: Valuation allowance
|
|
|
(140,192)
|
|
|
(108,843)
|
Net deferred tax liability
|
|
$
|
(90)
|
|
$
|
—
|
|
(a)
|
|
The Company’s
$135,711
deferred tax asset related to NOL carryforwards is net of
$9,288
of unrealized excess tax benefits related to stock based compensation.
|
If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Expiring
|
|
|
Total
|
|
2017-2022
|
|
2023-2025
|
|
2026-2028
|
|
2029-2031
|
|
2032-2036
|
Federal NOL carryforwards
|
|
$
|
387,745
|
|
$
|
56,979
|
|
$
|
65,878
|
|
$
|
32,714
|
|
$
|
53,806
|
|
$
|
178,368
|
As a result of the write-down of oil and natural gas properties discussed
in
Notes 2
and
13
,
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 valuation allowance for a portion of the deferred tax asset. The valuation allowance was
$140,192
as of
December 31, 2016
.
The Company had no significant unrecognized tax benefits at
December 31, 2016
. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 200
3
through 201
6
remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.
The Company 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.
The following table presents
a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations
:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax rate reconciliation
|
|
2016
|
|
2015
|
|
2014
|
Income tax expense computed at the statutory federal income tax rate
|
|
|
35%
|
|
|
35%
|
|
|
35%
|
Percentage depletion carryforward
|
|
|
—%
|
|
|
—%
|
|
|
—%
|
State taxes net of federal benefit
|
|
|
—%
|
|
|
1%
|
|
|
1%
|
Restricted stock and stock options
|
|
|
—%
|
|
|
—%
|
|
|
—%
|
Section 162(m)
|
|
|
(1)%
|
|
|
(1)%
|
|
|
2%
|
Valuation allowance
|
|
|
(34)%
|
|
|
(54)%
|
|
|
—%
|
Effective income tax rate
|
|
|
—%
|
|
|
(19)%
|
|
|
38%
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
|
|
For the Year Ended December 31,
|
Components of income tax expense
|
|
2016
|
|
2015
|
|
2014
|
Current federal income tax benefit
|
|
$
|
(104)
|
|
$
|
—
|
|
$
|
—
|
Current state income tax expense
|
|
|
—
|
|
|
—
|
|
|
—
|
Deferred federal income tax (benefit) expense
|
|
|
—
|
|
|
(69,087)
|
|
|
22,373
|
Deferred state income tax (benefit) expense
|
|
|
90
|
|
|
(1,282)
|
|
|
761
|
Valuation allowance
|
|
|
—
|
|
|
108,843
|
|
|
—
|
Total income tax expense
|
|
$
|
(14)
|
|
$
|
38,474
|
|
$
|
23,134
|
.
Note 12
- Asset Reti
rement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2016
|
|
2015
|
Asset retirement obligations at January 1, 2016
|
|
$
|
5,107
|
|
$
|
6,674
|
Accretion expense
|
|
|
958
|
|
|
660
|
Liabilities incurred
|
|
|
84
|
|
|
165
|
Liabilities settled
|
|
|
(2,378)
|
|
|
(2,964)
|
Revisions to estimate
|
|
|
2,890
|
|
|
572
|
Asset retirement obligations at end of period
|
|
|
6,661
|
|
|
5,107
|
Less: Current asset retirement obligations
|
|
|
(2,729)
|
|
|
(790)
|
Long-term asset retirement obligations at December 31, 2016
|
|
$
|
3,932
|
|
$
|
4,317
|
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at
December 31, 2016
and
2015
as long-term restricted investments were
$3,332
and
$3,309
, respectively.
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 13
– Supplemental Information on Oil and N
atural Gas Properties (Unaudited)
The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Evaluated Properties
(a)
|
|
|
|
|
|
|
|
|
|
Beginning of period balance
|
|
$
|
2,335,223
|
|
$
|
2,077,985
|
|
$
|
1,701,577
|
Capitalized G&A expenses
|
|
|
12,222
|
|
|
10,529
|
|
|
10,071
|
Property acquisition costs
(b)
|
|
|
216,561
|
|
|
26,726
|
|
|
94,541
|
Exploration costs
|
|
|
38,612
|
|
|
81,320
|
|
|
118,251
|
Development costs
|
|
|
151,735
|
|
|
138,663
|
|
|
153,545
|
End of period balance
|
|
$
|
2,754,353
|
|
$
|
2,335,223
|
|
$
|
2,077,985
|
Unevaluated Properties
(a)(
c)
|
|
|
|
|
|
|
|
|
|
Beginning of period balance
|
|
$
|
132,181
|
|
$
|
142,525
|
|
$
|
43,222
|
Property acquisition costs
(b)
|
|
|
548,673
|
|
|
5,520
|
|
|
128,342
|
Exploration costs
|
|
|
8,631
|
|
|
4,576
|
|
|
11,177
|
Capitalized interest expenses
|
|
|
19,857
|
|
|
10,459
|
|
|
4,295
|
Transfers to Evaluated Properties
|
|
|
(40,621)
|
|
|
(30,899)
|
|
|
(44,511)
|
End of period balance
|
|
$
|
668,721
|
|
$
|
132,181
|
|
$
|
142,525
|
Accumulated depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
Beginning of period balance
|
|
$
|
1,756,018
|
|
$
|
1,478,355
|
|
$
|
1,420,612
|
Provision charged to expense
|
|
|
71,330
|
|
|
69,228
|
|
|
56,663
|
Write-down of oil and natural gas properties
(a)
|
|
|
95,788
|
|
|
208,435
|
|
|
—
|
Sale of mineral interests
|
|
|
24,537
|
|
|
—
|
|
|
1,080
|
End of period balance
|
|
$
|
1,947,673
|
|
$
|
1,756,018
|
|
$
|
1,478,355
|
|
(a)
|
|
The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting.
|
|
(b)
|
|
See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions
.
|
|
(c)
|
|
Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The majority of these costs are primarily associated with the Company’s
focus areas of its
future
development
program
and are expected to be evaluated over
ten
to
fifteen
years. T
he Company’s unevaluated property balance
of $668,721 as of December 31, 2016,
consisted of
$123,345
,
$521,520
and
$23,856
of costs attributable to our Monarch
, Wild
H
orse and Ranger
operating area
s
,
respectively.
|
Subsequent to
December 31, 2016
, and through
February 22, 2017
, the Company drill
ed
four
gross (
3.4
net) horizontal wells and completed
five
gross (
3.4
net) horizontal wells and had
five
gross (
4.1
net) horizontal wells a
waiting completion.
Depletion per unit-of-production, on a BOE basis, amounted to
$12.81
,
$19.74
and
$27.51
for the years ended
December 31, 2016
,
2015
, and
2014
, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to
$6.88
,
$7.71
, and
$10.85
for the years ended
December 31, 2016
,
2015
, and
2014
, respectively.
Estimated Reserves
The Company’s proved oil and natural gas reserves at
December 31, 2016
,
2015
and
2014
have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
|
|
For the Year Ended December 31,
|
Proved developed and undeveloped reserves:
|
|
2016
|
|
2015
|
|
2014
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
43,348
|
|
25,733
|
|
11,898
|
Revisions to previous estimates
|
|
(5,738)
|
|
(1,632)
|
|
(243)
|
Purchase of reserves in place
|
|
25,054
|
|
2,932
|
|
3,223
|
Sale of reserves in place
|
|
(1,718)
|
|
(23)
|
|
—
|
Extensions and discoveries
|
|
14,479
|
|
19,127
|
|
12,547
|
Production
|
|
(4,280)
|
|
(2,789)
|
|
(1,692)
|
End of period
|
|
71,145
|
|
43,348
|
|
25,733
|
Natural Gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
65,537
|
|
42,548
|
|
17,751
|
Revisions to previous estimates
|
|
13,929
|
|
4,870
|
|
(215)
|
Purchase of reserves in place
|
|
36,474
|
|
2,915
|
|
8,591
|
Sale of reserves in place
|
|
(2,765)
|
|
(105)
|
|
—
|
Extensions and discoveries
|
|
17,194
|
|
19,621
|
|
18,641
|
Production
|
|
(7,758)
|
|
(4,312)
|
|
(2,220)
|
End of period
|
|
122,611
|
|
65,537
|
|
42,548
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed reserves:
|
|
2016
|
|
2015
|
|
2014
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
22,257
|
|
14,006
|
|
5,960
|
End of period
|
|
32,920
|
|
22,257
|
|
14,006
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
38,157
|
|
25,171
|
|
9,059
|
End of period
|
|
61,871
|
|
38,157
|
|
25,171
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
28,617
|
|
18,201
|
|
7,470
|
End of period
|
|
43,232
|
|
28,617
|
|
18,201
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
21,091
|
|
11,727
|
|
5,938
|
End of period
|
|
38,225
|
|
21,091
|
|
11,727
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
27,380
|
|
17,377
|
|
8,692
|
End of period
|
|
60,740
|
|
27,380
|
|
17,377
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
25,654
|
|
14,623
|
|
7,387
|
End of period
|
|
48,348
|
|
25,654
|
|
14,623
|
Total Proved Reserves:
The Company ended
2016
with estimated net proved reserves of
91,580
MBOE, representing a
69%
increase over
2015
year-end estimated net proved reserves of
54,271
MBOE. The Company added
48,477
MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of
29
gross (
20.9
net) wells. This increase was primarily offset by
11,168
M
BOE related to divestitures,
2016
production and revisions primarily due to pricing.
The Company ended 2015 with estimated net proved reserves of
54,271
MBOE, representing a
65%
increase over 2014 year-end estimated net proved reserves of
32,824
MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of
36
gross (
27.1
net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions.
The Company ended 2014 with estimated net proved reserves of
32,824
MBOE, representing a
121%
increase over 2013 year-end estimated net proved reserves of
14,857
MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of
34
gross (
28.7
net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions.
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
Proved Undeveloped Reserves:
The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within
five
years of the date they are first booked as PUDs. The Company’s PUDs increased
88%
to
48,348
MBOE from
25,654
MBOE at
December 31, 2016
and
2015
, respectively. The Company added
17,482
MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added
12,035
MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of
6,823
MBOE
, or
27%
,
inclu
ded in the year-end
2015
PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately
$43,415
, net.
The Company’s PUDs increased
75%
to
25,654
MBOE from
14,623
MBOE at December 31, 2015 and 2014, respectively. The Company added
13,774
MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of
2,742
MBOE, or
19%
, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately
$55,933
, net.
The Company’s PUDs increased
98%
to
14,623
MBOE from
7,387
MBOE at December 31, 2014 and 2013, respectively. The Company added
10,125
MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of
1,757
MBOE, or
24%
, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $
34,619
, net. Also offsetting the increase was the removal of
1,132
MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development.
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at
December 31, 2016
. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
Average 12-month price, net of differentials, per Mcf of natural gas
(a)
|
|
$
|
2.71
|
|
$
|
2.73
|
|
$
|
6.38
|
Average 12-month price, net of differentials, per barrel of oil
(b)
|
|
$
|
40.03
|
|
$
|
47.25
|
|
$
|
86.30
|
|
(a)
|
|
Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.
|
|
(b)
|
|
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
|
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Future cash inflows
|
|
$
|
3,180,005
|
|
$
|
2,227,463
|
|
$
|
2,492,178
|
Future costs
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(974,667)
|
|
|
(827,555)
|
|
|
(873,469)
|
Development and net abandonment
|
|
|
(384,117)
|
|
|
(239,100)
|
|
|
(288,081)
|
Future net inflows before income taxes
|
|
|
1,821,221
|
|
|
1,160,808
|
|
|
1,330,628
|
Future income taxes
|
|
|
(1,602)
|
|
|
—
|
|
|
(164,490)
|
Future net cash flows
|
|
|
1,819,619
|
|
|
1,160,808
|
|
|
1,166,138
|
10% discount factor
|
|
|
(1,009,787)
|
|
|
(589,918)
|
|
|
(586,596)
|
Standardized measure of discounted future net cash flows
|
|
$
|
809,832
|
|
$
|
570,890
|
|
$
|
579,542
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Standardized measure at the beginning of the period
|
|
$
|
570,890
|
|
$
|
579,542
|
|
$
|
283,946
|
Sales and transfers, net of production costs
|
|
|
(150,628)
|
|
|
(110,476)
|
|
|
(120,518)
|
Net change in sales and transfer prices, net of production costs
|
|
|
(103,136)
|
|
|
(286,660)
|
|
|
(156,066)
|
Net change due to purchases and sales of in place reserves
|
|
|
260,859
|
|
|
37,616
|
|
|
111,331
|
Extensions, discoveries, and improved recovery, net of future production and development costs incurred
|
|
|
180,228
|
|
|
184,469
|
|
|
299,192
|
Changes in future development cost
|
|
|
82,320
|
|
|
108,216
|
|
|
186,605
|
Revisions of quantity estimates
|
|
|
(35,938)
|
|
|
(12,625)
|
|
|
(7,673)
|
Accretion of discount
|
|
|
57,091
|
|
|
62,968
|
|
|
30,114
|
Net change in income taxes
|
|
|
16
|
|
|
35,407
|
|
|
(32,940)
|
Changes in production rates, timing and other
|
|
|
(51,870)
|
|
|
(27,567)
|
|
|
(14,449)
|
Aggregate change
|
|
|
238,942
|
|
|
(8,652)
|
|
|
295,596
|
Standardized measure at the end of period
|
|
$
|
809,832
|
|
$
|
570,890
|
|
$
|
579,542
|
Note 14
–
Other
Commitments and contingencies
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
Operating leases
As of
December 31, 2016
, 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.
Effective October 27, 2016, the Company entered into a contract for the Cactus 3 Rig,
which
commence
d
drilling in mid-January 2017. The contract terms of the Cactus
3
Rig will end in July 2017.
The rig lease agreements include early termination provisions that obligate the Company to 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 lessee.
In January 2016, the Company decided to place the Cactus 1 Rig on standby and
was
required to pay a “standby” day
|
|
|
Callon Petroleum Company
|
Notes to the Consolidated Financial Statements
(All
dollar
amounts in thousands, except
per share and per unit
data)
|
Table of Contents
|
rate of $
15,000
per day, pursuant to the terms of the agreement
, a
llowing
t
he 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.
In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015)
. The Company paid approximately
$3,075
in reduced rental payments over the remainder of the lease term, which ended November 2015
. The amount was recognized as rig termination fee on the consolidated statements of operations for the
year
ende
d December 31, 2015.
Note 15
– S
ummarized Quarterly Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
30,698
|
|
$
|
45,145
|
|
$
|
55,927
|
|
$
|
69,081
|
Income (loss) from operations
(a)
|
|
|
(34,767)
|
|
|
(50,529)
|
|
|
16,651
|
|
|
21,168
|
Net income (loss)
(a)
|
|
|
(41,109)
|
|
|
(70,097)
|
|
|
21,139
|
|
|
(1,746)
|
Income (loss) available to common shares
|
|
|
(42,933)
|
|
|
(71,920)
|
|
|
19,315
|
|
|
(3,570)
|
Income (loss) per common share - basic
|
|
$
|
(0.51)
|
|
$
|
(0.61)
|
|
$
|
0.14
|
|
$
|
(0.02)
|
Income (loss) per common share - diluted
|
|
$
|
(0.51)
|
|
$
|
(0.61)
|
|
$
|
0.14
|
|
$
|
(0.02)
|
|
(a)
|
|
Loss from operations and net loss for the three months ended March, 31, 2016 and June 30, 2016 included write-downs of oil and natural gas properties of
$34,776
and
$61,012
, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
30,391
|
|
$
|
39,242
|
|
$
|
34,316
|
|
$
|
33,563
|
Income (loss) from operations
(a)
|
|
|
(12,889)
|
|
|
6,231
|
|
|
(83,910)
|
|
|
(118,542)
|
Net loss
(a)
|
|
|
(10,197)
|
|
|
(4,967)
|
|
|
(111,805)
|
|
|
(113,170)
|
Loss available to common shares
|
|
|
(12,171)
|
|
|
(6,940)
|
|
|
(113,779)
|
|
|
(115,144)
|
Loss per common share - basic
|
|
$
|
(0.21)
|
|
$
|
(0.11)
|
|
$
|
(1.72)
|
|
$
|
(1.58)
|
Loss per common share - diluted
|
|
$
|
(0.21)
|
|
$
|
(0.11)
|
|
$
|
(1.72)
|
|
$
|
(1.58)
|
|
(a)
|
|
Lo
ss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and natural gas pro
perties of
$87,301
and
$121,134
, respectively
.
|