INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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1.
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8.
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2.
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9.
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3.
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Revenue Recognition
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10.
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4.
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11.
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5.
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12.
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6.
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13.
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7.
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14.
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Note 1
- Description of Business and Basis of Presentation
Description of business
Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. 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 an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. The Company has historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through our acquisitions in 2018.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the
Footnotes to the
Financial Statements are presented in thousands, except for per share and per unit data.
The 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. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.
Note 2
– Summary
of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues, and expenses. Management regularly evaluates its estimates and assumptions, including those related to valuation of oil and natural gas properties, future asset retirement obligations, income taxes and valuation of deferred tax assets, fair value measurements as it relates to financial instruments, material transactions, and commodity derivatives, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Accounts Receivable
Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners.
Revenue Recognition and Natural Gas Balancing
Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances. Natural gas balancing receivables and payables were immaterial as of
December 31, 2018
and
2017
. See
Note 3
for additional information on revenue recognition.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities.
When applicable, proceeds from the sale or 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 case 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 sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at
10%
, plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called 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, 2018 and 2017, the 12-month average benchmark pricing used to estimate future net cash flows from proved reserves in accordance with the definitions and regulations of the SEC, including differential adjustments, was
$58.40
and
$51.34
per barrel of oil, respectively, and
$3.64
and
$2.98
per Mcf of natural gas, respectively. For the periods ended December 31, 2018 and 2017, the Company did
no
t recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. At December 31, 2016, the 12-month average benchmark pricing used, including differential adjustments, was
$42.75
per barrel of oil and
$2.48
per Mcf of natural gas and the Company recognized a
$95,788
write-down of oil and natural gas properties as a result of the ceiling test limitation.
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 of 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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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Other Property and Equipment
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
$1,078
,
$900
and
$793
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, 2018
,
2017
and
2016
, respectively. The accumulated depreciation on other property and equipment was
$16,562
and
$16,259
as of
December 31, 2018
and
2017
, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Capitalized Interest
The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended
December 31, 2018
,
2017
and
2016
, the Company capitalized
$56,151
,
$33,783
and
$19,857
of interest expense.
Deferred
Financing
Costs
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, deferred 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
$2,483
,
$2,150
and
$3,115
were recorded for the years ended
December 31, 2018
,
2017
and
2016
, respectively.
Asset Retirement Obligations
The Company records an estimate of the fair value of liabilities for obligations associated with the costs to retire tangible long-life assets. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. See
Note 13
for additional information.
Derivatives
Derivative contracts outstanding as of
December 31, 2018
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 7
and
8
for additional information regarding the Company’s derivative contracts.
Income Taxes
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 carryforwards 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 a future benefit will not be realized. As of
December 31, 2018
the valuation allowance was
$0
. See
Note 12
for additional information.
Share-Based Compensation
The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”), some of which are subject to achievement of certain performance conditions.
Stock Options.
For historical stock options the Company expected to settle in common stock, share-based compensation expense was 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
).
RSU
equity
awards and Cash-settleable RSU awards.
For 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 employees and
one
year for directors). Certain of the Company’s RSU awards 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.
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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For RSU equity awards with vesting terms subject to a performance 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 subject to a performance condition that the Company expects or is required to settle in cash, 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 fair value recognized over the vesting period (generally
three years
).
See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation.
Non-cash Investing and Supplemental
Cash Flow Information
The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated:
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For the Year Ended December 31,
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2018
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2017
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2016
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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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(52,757
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)
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$
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(39,532
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)
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$
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(613
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)
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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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—
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$
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—
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$
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8,679
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(a)
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During the three year period ended
2018
, the Company paid
no
federal income taxes.
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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.
Accounting Standards Updates
Recently issued ASUs - Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).
ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has engaged a third-party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the hindsight practical expedient when determining the lease term of existing contracts at the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.
Additionally, the Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASC Topic 842 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures.
The Company will adopt this guidance as of January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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adoption. At this time, the impact upon adoption of ASC Topic 842 is expected to result in recognition of additional operating liabilities, with corresponding right-of-use assets, ranging from
$45 million
to
$55 million
on the Company’s Consolidated Balance Sheet for leases existing as of January 1, 2019, of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The adoption of this standard is not expected to have a material impact on the Company’s Consolidated Statement of Income nor Consolidated Statement of Cash Flows.
Recently issued ASUs - Other
In June 2018, the FASB issued ASU No. 2018-07,
Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting
(“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.
Recently Adopted ASUs - Revenue Recognition
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 replaced most of the existing revenue recognition requirements in GAAP. See Note 3 for additional information on revenue recognition.
The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows:
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As reported
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Adjustments
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Presentation without adoption of ASC Topic 606
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Operating revenues
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Natural gas sales
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$
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56,726
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$
|
7,646
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$
|
64,372
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Total operating revenues
|
587,624
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|
7,646
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|
595,270
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Operating expenses
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Lease operating expenses
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$
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69,180
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$
|
7,646
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$
|
76,826
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Total operating expenses
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328,094
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|
7,646
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335,740
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Recently Adopted ASUs - Other
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
(“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with 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 Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”).
The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements.
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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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 adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.
In December 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topics 230): Restricted Cash
(“ASU 2016-18”). The objective 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 adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements.
Note 3 - Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.
Natural gas sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of revenues. For the
twelve months ended
December 31, 2018
,
$7,646
of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations. For the
twelve months ended
December 31, 2017
and
2016
,
$3,433
and
$1,727
of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at
December 31, 2018
and
2017
of
$87,061
and
$70,138
, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from oil and natural gas are included in accounts receivable on the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for
30
to
90
days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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Note 4 – Acquisitions and Dispositions
2018 Acquisitions
On August 31, 2018, the Company completed the acquisition of approximately
28,000
net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for
$539,519
, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See
Notes 6
and
11
for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:
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Evaluated oil and natural gas properties
|
$
|
253,089
|
|
Unevaluated oil and natural gas properties
|
287,000
|
|
Asset retirement obligations
|
(570
|
)
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Net assets acquired
|
$
|
539,519
|
|
The preliminary purchase price allocations 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.
In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for
$37,770
, including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for
$87,865
, including customary purchase price adjustments.
2017 Acquisitions
On February 13, 2017, the Company completed the acquisition of
29,175
gross (
16,688
net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of
$646,559
, 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 11
for additional information regarding the equity offering). The Company obtained an
82%
average working interest (
75%
average 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. The following table summarizes the estimated acquisition date fair values of the acquisition:
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Evaluated oil and natural gas properties
|
$
|
137,368
|
|
Unevaluated oil and natural gas properties
|
509,359
|
|
Asset retirement obligations
|
(168
|
)
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Net assets acquired
|
$
|
646,559
|
|
On June 5, 2017, the Company completed the acquisition of
7,031
gross (
2,488
net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for
$52,014
, including customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional
$200,000
of its
6.125%
senior notes due 2024 (“6.125% Senior Notes”) (see
Note 6
for additional information regarding the Company’s debt obligations).
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Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
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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 11
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
|
$
|
65,043
|
|
Unevaluated oil and natural gas properties
|
274,664
|
|
Asset retirement obligations
|
(20
|
)
|
Net assets acquired
|
$
|
339,687
|
|
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
9.3 million
shares of common stock (at an assumed offering price of
$11.74
per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of
$329,573
, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an
81%
average working interest (
61%
average net revenue interest) in the properties acquired in the Big Star Transaction. 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
|
$
|
96,194
|
|
Unevaluated oil and natural gas properties
|
233,387
|
|
Asset retirement obligations
|
(8
|
)
|
Net assets acquired
|
$
|
329,573
|
|
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.
Unaudited pro forma financial statements
The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Delaware Asset Acquisition, Ameredev Transaction, Plymouth Transaction, and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2018
|
(a)
|
|
2017
|
(a)
|
|
2016
|
(a)
|
Revenues
|
|
$
|
668,759
|
|
|
|
$
|
472,949
|
|
|
|
$
|
243,273
|
|
|
Income (loss) from operations
|
|
295,738
|
|
|
|
212,381
|
|
|
|
(39,730
|
)
|
|
Income (loss) available to common stockholders
|
|
336,730
|
|
|
|
184,064
|
|
|
|
(82,612
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.55
|
|
|
|
$
|
0.91
|
|
|
|
$
|
(0.50
|
)
|
|
Diluted
|
|
$
|
1.55
|
|
|
|
$
|
0.91
|
|
|
|
$
|
(0.50
|
)
|
|
|
|
(a)
|
The pro forma financial information was prepared assuming the Delaware Asset Acquisition occurred as of January 1, 2017, and the Ameredev Transaction, Plymouth Transaction, and Big Star Transaction occurred as of January 1, 2016.
|
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 Delaware Asset Acquisition, Ameredev Transaction, Big Star Transaction, and the Plymouth Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 5
- Earnings 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(share amounts in thousands)
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Net income (loss)
|
|
$
|
300,360
|
|
|
$
|
120,424
|
|
|
$
|
(91,813
|
)
|
Preferred stock dividends
|
|
(7,295
|
)
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Income (loss) available to common stockholders
|
|
$
|
293,065
|
|
|
$
|
113,129
|
|
|
$
|
(99,108
|
)
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
216,941
|
|
|
201,526
|
|
|
126,258
|
|
Dilutive impact of restricted stock
|
|
655
|
|
|
576
|
|
|
—
|
|
Weighted average shares outstanding for diluted income (loss) per share
(a)
|
|
217,596
|
|
|
202,102
|
|
|
126,258
|
|
|
|
|
|
|
|
|
Basic income (loss) per share
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
Diluted income (loss) per share
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
|
|
|
|
|
|
|
Stock options
(b)
|
|
—
|
|
|
—
|
|
|
15
|
|
Restricted stock
(b)
|
|
89
|
|
|
16
|
|
|
—
|
|
|
|
(a)
|
Because the Company reported a net loss available to common stockholders for the year ended
December 31, 2016
, no unvested stock awards were included in computing net 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-dilutive.
|
Note 6
– Borrowings
The Company’s borrowings consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
Principal components:
|
|
|
|
|
Senior secured revolving credit facility
|
|
$
|
200,000
|
|
|
$
|
25,000
|
|
6.125% senior unsecured notes due 2024
|
|
600,000
|
|
|
600,000
|
|
6.375% senior unsecured notes due 2026
|
|
400,000
|
|
|
—
|
|
Total principal outstanding
|
|
1,200,000
|
|
|
625,000
|
|
Premium on 6.125% Senior Notes, net of accumulated amortization
|
|
6,469
|
|
|
7,594
|
|
Unamortized deferred financing costs
|
|
(16,996
|
)
|
|
(12,398
|
)
|
Total carrying value of borrowings
(a)
|
|
$
|
1,189,473
|
|
|
$
|
620,196
|
|
|
|
(a)
|
Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of
$6,087
and
$4,863
as of December 31, 2018 and 2017, respectively.
|
Senior secured revolving credit
facility (“Credit Facility”)
On
May 25, 2017
, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of
May 25, 2022
. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include
17
institutional lenders. The total notional amount available under the Credit Facility is
$2,000,000
. 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. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to
$650,000
, but the Company elected an aggregate commitment amount of
$500,000
. On
November 7, 2017
, the Credit Facility’s borrowing base increased to
$700,000
with a reaffirmed commitment of
$500,000
, following the semi-annual review.
Effective
April 5, 2018
, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$825,000
, (2) increased the elected commitment amount to
$650,000
, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to
May 25, 2023
.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Effective
September 27, 2018
, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$1,100,000
, (2) increase the elected commitment amount to
$850,000
, and (3) amended various covenants and terms to reflect current market trends. As of
December 31, 2018
, the Credit Facility’s borrowing base remained at
$1,100,000
with an elected commitment amount of
$850,000
.
As of
December 31, 2018
, there was
$200,000
of principal and
$17,675
in letters of credit outstanding on the Credit Facility. For the year ended
December 31, 2018
, the Credit Facility had a weighted-average interest rate of
3.62%
, calculated as the LIBOR plus a tiered rate ranging from
1.25%
to
2.25%
, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of
0.375%
per annum, payable quarterly, on the unused portion of the borrowing base.
6.375%
Senior Notes
On
June 7, 2018
, the Company issued
$400,000
aggregate principal amount of
6.375%
Senior Notes with a maturity date of
July 1, 2026
and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$394,000
. The
6.375%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is
100%
owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
The Company may redeem the
6.375%
Senior Notes in accordance with the following terms: (1) prior to
July 1, 2021
, 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
106.375%
of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least
65%
of the principal will remain outstanding after such redemption; (2) prior to
July 1, 2021
, a redemption of all or part of the principal at a price of
100%
of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (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
103.188%
of principal if the redemption occurs on or after July 1, 2021, but before
July 1, 2022
, and (ii) of
102.125%
of principal if the redemption occurs on or after
July 1, 2022
, but before
July 1, 2023
, and (iii) of
101.063%
of principal if the redemption occurs on or after
July 1, 2023
, but before
July 1, 2024
, and (iv) of
100%
of principal if the redemption occurs on or after
July 1, 2024
.
Following a change of control, each holder of the
6.375%
Senior Notes may require the Company to repurchase all or a portion of the
6.375%
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.
6.125%
Senior Notes
On October 3, 2016, the Company issued
$400,000
aggregate principal amount of
6.125%
Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$391,270
. The
6.125%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is
100%
owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
On May 19, 2017, the Company issued an additional
$200,000
aggregate principal amount of its
6.125%
Senior Notes which with the existing
$400,000
aggregate principal amount of
6.125%
Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of
104.125%
and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$206,139
. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in
Note 4
) and for general corporate purposes.
The Company may redeem the
6.125%
Senior Notes in accordance with the following terms; (1) prior to
October 1, 2019
, a redemption of up to
35%
of the principal in an amount not greater than the net proceeds from certain equity offerings, and within
180
days of the closing date of such equity offerings, at a redemption price of
106.125%
of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least
65%
of the principal will remain outstanding after such redemption; (2) prior to
October 1, 2019
, a redemption of all or part of the principal at a price of
100%
of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
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.
Term loans
The Company historically held a term loan agreement since March 11, 2014. On October 8, 2014, the original term loan was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) with a maturity date of
October 8, 2021
. 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 Notes, 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).
Restrictive covenants
The Company’s Credit Facility and the indentures governing its
6.125%
and
6.375%
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, 2018.
Note 7
- Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see
Note 8
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 8
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. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
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
|
|
12/31/2018
|
|
12/31/2017
|
|
12/31/2018
|
|
12/31/2017
|
|
12/31/2018
|
|
12/31/2017
|
Oil
|
|
Current
|
|
Fair value of derivatives
|
|
$
|
60,097
|
|
|
$
|
—
|
|
|
$
|
(10,480
|
)
|
|
$
|
(27,744
|
)
|
|
$
|
49,617
|
|
|
$
|
(27,744
|
)
|
Oil
|
|
Non-current
|
|
Fair value of derivatives
|
|
—
|
|
|
—
|
|
|
(5,672
|
)
|
|
(1,284
|
)
|
|
(5,672
|
)
|
|
(1,284
|
)
|
Natural gas
|
|
Current
|
|
Fair value of derivatives
|
|
5,017
|
|
|
406
|
|
|
—
|
|
|
—
|
|
|
5,017
|
|
|
406
|
|
Natural gas
|
|
Non-current
|
|
Fair value of derivatives
|
|
—
|
|
|
—
|
|
|
(1,768
|
)
|
|
—
|
|
|
(1,768
|
)
|
|
—
|
|
Totals
|
|
|
|
|
|
$
|
65,114
|
|
|
$
|
406
|
|
|
$
|
(17,920
|
)
|
|
$
|
(29,028
|
)
|
|
$
|
47,194
|
|
|
$
|
(28,622
|
)
|
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, 2018
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
78,091
|
|
|
(12,977
|
)
|
|
65,114
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
(23,457
|
)
|
|
12,977
|
|
|
(10,480
|
)
|
Long-term liabilities: Fair value of derivatives
|
(7,440
|
)
|
|
—
|
|
|
(7,440
|
)
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2017
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
406
|
|
|
—
|
|
|
406
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
(27,744
|
)
|
|
—
|
|
|
(27,744
|
)
|
Long-term liabilities: Fair value of derivatives
|
(1,284
|
)
|
|
—
|
|
|
(1,284
|
)
|
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,
|
|
|
2018
|
|
2017
|
|
2016
|
Oil derivatives
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
(27,510
|
)
|
|
$
|
(9,067
|
)
|
|
$
|
17,801
|
|
Net gain (loss) on fair value adjustments
|
|
72,973
|
|
|
(11,426
|
)
|
|
(37,543
|
)
|
Total gain (loss) on oil derivatives
|
|
$
|
45,463
|
|
|
$
|
(20,493
|
)
|
|
$
|
(19,742
|
)
|
Natural gas derivatives
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
238
|
|
|
$
|
594
|
|
|
$
|
102
|
|
Net gain (loss) on fair value adjustments
|
|
2,843
|
|
|
998
|
|
|
(593
|
)
|
Total gain (loss) on natural gas derivatives
|
|
$
|
3,081
|
|
|
$
|
1,592
|
|
|
$
|
(491
|
)
|
|
|
|
|
|
|
|
Total gain (loss) on oil & natural gas derivatives
|
|
$
|
48,544
|
|
|
$
|
(18,901
|
)
|
|
$
|
(20,233
|
)
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
For the Full Year of
|
Oil contracts (WTI)
|
|
2019
|
|
2020
|
Puts
|
|
|
|
|
Total volume (Bbls)
|
|
912,500
|
|
|
—
|
|
Weighted average price per Bbl
|
|
$
|
65.00
|
|
|
$
|
—
|
|
Put spreads
|
|
|
|
|
Total volume (Bbls)
|
|
912,500
|
|
|
—
|
|
Weighted average price per Bbl
|
|
|
|
|
Floor (long put)
|
|
$
|
65.00
|
|
|
$
|
—
|
|
Floor (short put)
|
|
$
|
42.50
|
|
|
$
|
—
|
|
Collar contracts combined with short puts (three-way collars)
|
|
|
|
|
Total volume (Bbls)
|
|
4,564,000
|
|
|
—
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
|
$
|
67.62
|
|
|
$
|
—
|
|
Floor (long put)
|
|
$
|
56.60
|
|
|
$
|
—
|
|
Floor (short put)
|
|
$
|
43.60
|
|
|
$
|
—
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
|
4,746,500
|
|
|
4,024,000
|
|
Weighted average price per Bbl
|
|
$
|
(4.72
|
)
|
|
$
|
(1.51
|
)
|
|
|
|
|
|
Natural gas contracts (Henry Hub)
|
|
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
Total volume (MMBtu)
|
|
8,282,500
|
|
|
—
|
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling (short call)
|
|
$
|
3.46
|
|
|
$
|
—
|
|
Floor (long put)
|
|
$
|
2.91
|
|
|
$
|
—
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (MMBtu)
|
|
11,321,000
|
|
|
4,758,000
|
|
Weighted average price per MMBtu
|
|
$
|
(1.23
|
)
|
|
$
|
(1.12
|
)
|
Note 8
-
Fair Value Measurements
The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair value of financial instruments
Cash, cash equivalents, and restricted investments.
The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt.
The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
Credit Facility
(a)
|
$
|
200,000
|
|
|
$
|
200,000
|
|
|
$
|
25,000
|
|
|
$
|
25,000
|
|
6.125% Senior Notes
(b)
|
595,788
|
|
|
558,000
|
|
|
595,196
|
|
|
618,000
|
|
6.375% Senior Notes
(b)
|
393,685
|
|
|
372,000
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
1,189,473
|
|
|
$
|
1,130,000
|
|
|
$
|
620,196
|
|
|
$
|
643,000
|
|
|
|
(b)
|
The fair value was based upon Level 2 inputs. See
Note 6
for additional information about the Company’s
6.125%
and
6.375%
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 7
for additional information regarding the Company’s derivative instruments.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
Classification
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
65,114
|
|
|
$
|
—
|
|
|
$
|
65,114
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
—
|
|
|
(17,920
|
)
|
|
—
|
|
|
(17,920
|
)
|
Total net assets
|
|
|
$
|
—
|
|
|
$
|
47,194
|
|
|
$
|
—
|
|
|
$
|
47,194
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
Classification
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
406
|
|
|
$
|
—
|
|
|
$
|
406
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
—
|
|
|
(29,028
|
)
|
|
—
|
|
|
(29,028
|
)
|
Total net liabilities
|
|
|
$
|
—
|
|
|
$
|
(28,622
|
)
|
|
$
|
—
|
|
|
$
|
(28,622
|
)
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions.
The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.
Note 9
–
Employee Benefit Plans
Savings and Protection Plan (“401(k) Plan”)
The 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 common stock 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 were
$2,082
,
$1,292
and
$1,018
in the years
2018
,
2017
and
2016
, respectively. Of those amounts contributed, the value of common stock contributed for each period was
$600
,
$313
, and
$277
, respectively.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 10
-
Share-Based Compensation
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, 2018
, shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2018 Plan, were
9,806,953
.
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 and as amended through May 14, 2015, authorized and reserved for issuance
5,141,000
shares. As of May 10, 2018, no more shares will be issued from the 2011 Plan and the remaining
1,322,742
shares authorized and available for issuance under the 2011 Plan transferred into the 2018 Omnibus Incentive Plan (the “2018 Plan”). Shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing prior to the effective date of the 2018 Plan, will increase the authorized shares available to the 2018 Plan.
RSU equity awards
. RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards.
For performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-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. Performance-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-settled RSU
awards.
Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan 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 performance-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 performance-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.
2018 Omnibus Incentive Plan (the “2018 Plan”)
The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance
9.4 million
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 2018 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the 2011 Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional
1,322,742
shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to
10,722,742
at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan.
RSU equity
awards
. RSU equity awards issued under the 2018 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2018 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for any 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 performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-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. Performance-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.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Cash-settled RSU
awards.
Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan 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 performance-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 performance-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.
The following table presents share-based compensation expense for each respective period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
Share-based compensation cost for:
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
RSU equity awards
(a)
|
$
|
9,460
|
|
|
$
|
—
|
|
|
$
|
10,225
|
|
|
$
|
—
|
|
|
$
|
4,536
|
|
|
$
|
—
|
|
Cash-settleable RSU awards
(a)
|
—
|
|
|
336
|
|
|
—
|
|
|
4,294
|
|
|
—
|
|
|
12,285
|
|
Total share-based compensation cost
(b)
|
$
|
9,460
|
|
|
$
|
336
|
|
|
$
|
10,225
|
|
|
$
|
4,294
|
|
|
$
|
4,536
|
|
|
$
|
12,285
|
|
|
|
(a)
|
Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in
$6,351
recorded on the Consolidated Statements of Operations as settled share-based awards for the year ended December 31, 2017.
|
|
|
(b)
|
The portion of this share-based compensation cost that was included in general and administrative expense totaled
$6,362
,
$4,966
and
$9,547
for the years ended
December 31, 2018
,
2017
and
2016
, respectively, and the portion capitalized to oil and gas properties was
$3,434
,
$3,202
and
$7,274
, for the years ended
December 31, 2018
,
2017
, and
2016
, respectively.
|
The following table presents the unrecognized compensation cost for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Unrecognized compensation cost related to:
|
|
2018
|
|
2017
|
|
2016
|
Unvested RSU equity awards
|
|
$
|
15,720
|
|
|
$
|
13,158
|
|
|
$
|
7,276
|
|
Unvested cash-settleable RSU awards
|
|
1,822
|
|
|
3,776
|
|
|
8,948
|
|
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
two
years.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Consolidated Balance Sheets Classification
|
|
2018
|
|
2017
|
Cash-settleable RSU awards (current)
|
|
$
|
1,390
|
|
|
$
|
4,621
|
|
Cash-settleable RSU awards (non-current)
|
|
2,067
|
|
|
3,490
|
|
Total cash-settleable RSU awards
|
|
$
|
3,457
|
|
|
$
|
8,111
|
|
Stock Options
The Company issued no stock options for the past
three
years and all existing options expired by year end December 31, 2017. 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
.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Restricted Stock Units
The following table represents unvested stock-settleable restricted stock activity for the year ended
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
|
(shares in 000s)
|
|
Number of Shares
|
|
Grant-Date Fair Value per Share
|
|
Years Over Which Expense is Expected to be Recognized
|
Outstanding at the beginning of the period
|
|
1,790
|
|
|
$
|
11.54
|
|
|
|
Granted
(a)
|
|
872
|
|
|
13.89
|
|
|
|
Vested
(b)
|
|
(506
|
)
|
|
9.56
|
|
|
|
Forfeited
|
|
(53
|
)
|
|
11.43
|
|
|
|
Outstanding at the end of the period
|
|
2,103
|
|
|
$
|
13.24
|
|
|
1.85
|
|
|
(a)
|
Includes
208
performance-based RSUs that will vest at a range of
0%
-
200%
.
|
|
|
(b)
|
The fair value of shares vested was
$6,344
.
|
For the year ended
December 31, 2017
, the Company granted
1,173,094
RSUs with a weighted average grant-date fair value of
$12.25
per share. The fair value of shares vested during
2017
was
$9,045
. For the year ended
December 31, 2016
, the Company granted
684,090
RSUs with a weighted average grant-date fair value of
$12.63
per share. The fair value of shares vested during
2016
was
$2,608
.
As of
December 31, 2018
, 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 2019
|
|
190
|
|
|
17
|
|
|
364
|
|
Vesting in 2020
|
|
323
|
|
|
—
|
|
|
645
|
|
Vesting in 2021
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
146
|
|
|
146
|
|
|
146
|
|
Total cash-settleable RSUs
|
|
659
|
|
|
163
|
|
|
1,155
|
|
For the year ended
December 31, 2018
,
207,261
performance-based cash-settled RSUs, subject to the peer performance-based vesting described above, vested at between
100%
to
163%
of their issued units, depending on the date of the vesting, resulting in cash payments of
$89
in
2018
and payable amounts of
$1,296
in
2019
. Also during
2018
,
129,753
non-performance-based cash settled RSUs vested, resulting in cash payments of
$1,834
in
2018
. During
2017
,
335,471
performance-based cash-settled RSUs subject to the peer performance-based vesting described above vested at between
142%
to
200%
of their underlying issued units, depending on the date of the vesting, resulting in cash payments of
$3,986
in
2017
and
$3,062
in
2018
. Also during
2017
,
43,031
non-performance-based cash settled RSUs vested, resulting in cash payments of
$526
in
2017
.
Note 11
– Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by the Company’s Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of
10%
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 Company’s Board of Directors. Preferred Stock dividends were
$7,295
for each year in
2018
,
2017
and
2016
.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, 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
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
determined under the certificate of designations for the Preferred Stock. If the change of control occurred on
December 31, 2018
, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of
$6.49
as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately
7.7
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 thousand
shares of Preferred Stock for
719 thousand
shares of common stock. As of
December 31, 2018
, the Company had
1,458,948
shares of its Preferred Stock issued and outstanding.
Common Stock
On May 30, 2018, the Company completed an underwritten public offering of
25.3 million
shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately
$287,988
. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in Note 4.
On December 19, 2016, the Company completed an underwritten public offering of
40 million
shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately
$634,934
. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in
Note 4
.
On September 6, 2016, the Company completed an underwritten public offering of
29.9 million
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 4
.
On May 26, 2016, the Company issued
9.3 million
shares of common stock to partially fund the Big Star Transaction, described in
Note 4
, 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
25.3 million
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 4
, and other working interest acquisitions.
On March 9, 2016, the Company completed an underwritten public offering of
15.3 million
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.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 12
-
Income 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,
|
|
|
2018
|
|
2017
|
Deferred tax asset
(a)
|
|
|
|
|
Federal net operating loss carryforward
|
|
$
|
151,497
|
|
|
$
|
97,437
|
|
Interest expense carryforward
(b)
|
|
7,335
|
|
|
—
|
|
Statutory depletion carryforward
|
|
5,381
|
|
|
5,381
|
|
Alternative minimum tax credit carryforward
(b)
|
|
—
|
|
|
52
|
|
Asset retirement obligations
|
|
2,347
|
|
|
572
|
|
Derivatives asset
|
|
—
|
|
|
6,186
|
|
Unvested RSU equity awards
|
|
2,751
|
|
|
1,749
|
|
Other
|
|
991
|
|
|
2,401
|
|
Deferred tax asset before valuation allowance
|
|
170,302
|
|
|
113,778
|
|
Deferred tax liability
(a)
|
|
|
|
|
Oil and natural gas properties
|
|
169,682
|
|
|
54,264
|
|
Derivatives liability
|
|
10,184
|
|
|
—
|
|
Total deferred tax liability
|
|
179,866
|
|
|
54,264
|
|
Net deferred tax asset (liability) before valuation allowance
|
|
(9,564
|
)
|
|
59,514
|
|
Less: Valuation allowance
|
|
—
|
|
|
(60,919
|
)
|
Net deferred tax liability
|
|
$
|
(9,564
|
)
|
|
$
|
(1,405
|
)
|
|
|
(a)
|
Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Act lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of
December 31, 2018
and
2017
, the Company’s tax rate applied was 21%. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, in 2017 the Company recorded a
$40,611
reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance.
|
|
|
(b)
|
The 2017 Tax Act revised the rules regarding the deductibility of net interest expense incurred in tax years beginning after 2017, with non-deductible amounts being carried forward to future taxable years.
|
|
|
(c)
|
The 2017 Tax Act repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income.
|
U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Act for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset
80%
of the Company’s taxable income in any year of utilization. As of
December 31, 2018
, Post-2017 NOLs amounted to
$58,298
. If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Act, will expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Expiring
|
|
|
Total
|
|
2019-2024
|
|
2025-2027
|
|
2028-2030
|
|
2031-2033
|
|
2034-2038
|
Federal NOL carryforwards
|
|
$
|
662,712
|
|
|
$
|
115,387
|
|
|
$
|
39,714
|
|
|
$
|
32,111
|
|
|
$
|
22,164
|
|
|
$
|
453,336
|
|
As a result of a historical write-down of oil and natural gas properties in 2016, discussed in
Notes 2
and
Supplemental Information on Oil and Natural Gas Operations
, the Company had incurred a cumulative
three
year loss. Because of the impact the cumulative loss had 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 the net deferred tax asset. As of December 31, 2017, the valuation allowance was
$60,919
. During 2018, the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to
$0
as of
December 31, 2018
.
The Company had no significant unrecognized tax benefits at
December 31, 2018
. 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.
The Company provides for income taxes at a statutory rate of
21%
adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, 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:
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax rate reconciliation
|
|
2018
|
|
2017
|
|
2016
|
Income tax expense computed at the statutory federal income tax rate
|
|
21
|
%
|
|
35
|
%
|
|
35
|
%
|
State taxes net of federal expense
|
|
1
|
%
|
|
1
|
%
|
|
—
|
%
|
Section 162(m)
|
|
1
|
%
|
|
—
|
%
|
|
(1
|
)%
|
Valuation allowance
|
|
(20
|
)%
|
|
(35
|
)%
|
|
(34
|
)%
|
Effective income tax rate
|
|
3
|
%
|
|
1
|
%
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax expense
|
|
2018
|
|
2017
|
|
2016
|
Current federal income tax benefit
|
|
$
|
—
|
|
|
$
|
(48
|
)
|
|
$
|
(104
|
)
|
Deferred federal income tax (benefit) expense
|
|
3,594
|
|
|
(45
|
)
|
|
—
|
|
Deferred state income tax expense
|
|
4,516
|
|
|
1,366
|
|
|
90
|
|
Total income tax (benefit) expense
|
|
$
|
8,110
|
|
|
$
|
1,273
|
|
|
$
|
(14
|
)
|
.
Note 13
- Asset Retirement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
Asset retirement obligations at January 1, 2018 and 2017, respectively
|
|
$
|
6,020
|
|
|
$
|
6,661
|
|
Accretion expense
|
|
874
|
|
|
677
|
|
Liabilities incurred
|
|
1,543
|
|
|
278
|
|
Liabilities settled
|
|
(1,288
|
)
|
|
(711
|
)
|
Dispositions
|
|
(614
|
)
|
|
—
|
|
Revisions to estimate
|
|
7,757
|
|
|
(885
|
)
|
Asset retirement obligations at end of period
|
|
14,292
|
|
|
6,020
|
|
Less: Current asset retirement obligations
|
|
(3,887
|
)
|
|
(1,295
|
)
|
Long-term asset retirement obligations at December 31, 2018 and 2017, respectively
|
|
$
|
10,405
|
|
|
$
|
4,725
|
|
2018
|
|
•
|
Liabilities incurred
include additions from acquisitions, primarily the Delaware Asset Acquisition completed in the third quarter of 2018, as well as additions from new wells drilled during the year.
|
|
|
•
|
Liabilities settled
include the retirement of
26
wells in
2018
.
|
|
|
•
|
Dispositions
are primarily attributable to the sale of oil and gas properties in the second quarter of
2018
.
|
|
|
•
|
Revisions to estimates
were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.
|
2017
|
|
•
|
Liabilities incurred
were primarily a result of additions from new wells drilled during the year.
|
|
|
•
|
Liabilities settled
include the retirement of
18
wells in
2017
.
|
|
|
•
|
Revisions to estimates
were due to changes in timing of abandonment activities.
|
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, 2018
and
2017
as long-term restricted investments were
$3,424
and
$3,372
, 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.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
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, 2018
, the Company had contracts for
five
horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate.
Other commitments
In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a
two
-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.
In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, Reagan and Upton counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our
15,000
Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
Subsequent Event
In January 2019, Callon Petroleum Operating Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, and Reagan counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term
10,000
Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Estimated Reserves
The Company’s proved oil and natural gas reserves at
December 31, 2018
,
2017
and
2016
have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum and geological firm (the “Reserve Engineering Firm”). 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.
Extrapolation of performance history and material balance estimates were utilized by the Company’s Reserve Engineering 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.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed and undeveloped reserves:
|
|
2018
|
|
2017
|
|
2016
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
107,072
|
|
|
71,145
|
|
|
43,348
|
|
Purchase of reserves in place
|
|
30,756
|
|
|
8,388
|
|
|
25,054
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(1,718
|
)
|
Extensions and discoveries
|
|
67,763
|
|
|
39,267
|
|
|
14,479
|
|
Revisions to previous estimates
|
|
(8,982
|
)
|
|
(1,548
|
)
|
|
(4,544
|
)
|
Reclassifications due to changes in development plan
|
|
(7,069
|
)
|
|
(3,623
|
)
|
|
(1,194
|
)
|
Production
|
|
(9,443
|
)
|
|
(6,557
|
)
|
|
(4,280
|
)
|
End of period
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
Natural Gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
179,410
|
|
|
122,611
|
|
|
65,537
|
|
Purchase of reserves in place
|
|
53,563
|
|
|
12,711
|
|
|
36,474
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(2,765
|
)
|
Extensions and discoveries
|
|
103,149
|
|
|
48,648
|
|
|
17,194
|
|
Revisions to previous estimates
|
|
41,767
|
|
|
18,121
|
|
|
16,842
|
|
Reclassifications due to changes in development plan
|
|
(11,976
|
)
|
|
(11,785
|
)
|
|
(2,913
|
)
|
Production
|
|
(15,447
|
)
|
|
(10,896
|
)
|
|
(7,758
|
)
|
End of period
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
Total (MBOE):
|
|
|
|
|
|
|
Beginning of period
|
|
136,974
|
|
|
91,580
|
|
|
54,271
|
|
Purchase of reserves in place
|
|
39,683
|
|
|
10,507
|
|
|
31,133
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(2,179
|
)
|
Extensions and discoveries
|
|
84,955
|
|
|
47,375
|
|
|
17,345
|
|
Revisions to previous estimates
|
|
(2,021
|
)
|
|
1,472
|
|
|
(1,737
|
)
|
Reclassifications due to changes in development plan
|
|
(9,065
|
)
|
|
(5,587
|
)
|
|
(1,680
|
)
|
Production
|
|
(12,018
|
)
|
|
(8,373
|
)
|
|
(5,573
|
)
|
End of period
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed reserves:
|
|
2018
|
|
2017
|
|
2016
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
51,920
|
|
|
32,920
|
|
|
22,257
|
|
End of period
|
|
92,202
|
|
|
51,920
|
|
|
32,920
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
104,389
|
|
|
61,871
|
|
|
38,157
|
|
End of period
|
|
218,417
|
|
|
104,389
|
|
|
61,871
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
69,318
|
|
|
43,232
|
|
|
28,617
|
|
End of period
|
|
128,605
|
|
|
69,318
|
|
|
43,232
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
55,152
|
|
|
38,225
|
|
|
21,091
|
|
End of period
|
|
87,895
|
|
|
55,152
|
|
|
38,225
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
75,021
|
|
|
60,740
|
|
|
27,380
|
|
End of period
|
|
132,049
|
|
|
75,021
|
|
|
60,740
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
67,656
|
|
|
48,348
|
|
|
25,654
|
|
End of period
|
|
109,903
|
|
|
67,656
|
|
|
48,348
|
|
Total proved reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
107,072
|
|
|
71,145
|
|
|
43,348
|
|
End of period
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
179,410
|
|
|
122,611
|
|
|
65,537
|
|
End of period
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
136,974
|
|
|
91,580
|
|
|
54,271
|
|
End of period
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
Total Proved Reserves
The Company ended
2018
with estimated net proved reserves of
238,508
MBOE, representing a
74%
increase
over
2017
year-end estimated net proved reserves of
136,974
MBOE. The Company added
124,638
MBOE primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of
70
gross (
57.5
net) wells. This
increase
was offset by
2018
production, negative revisions of previous estimates of
2,021
MBOE primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of
9,065
MBOE from
19
PUD locations primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.
The Company ended 2017 with estimated net proved reserves of
136,974
MBOE, representing a
50%
increase over 2016 year-end estimated net proved reserves of
91,580
MBOE. The Company added
57,881
MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of
49
gross (
38.2
net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified
13
PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations.
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
MBOE related to divestitures, 2016 production, revisions primarily due to pricing, and reclassifications of
4
PUD locations as a result of a change in the Company’s development and dilling plans within its operating areas.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Capitalized Costs
Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
Oil and natural gas properties:
|
|
|
|
|
Evaluated properties
|
|
$
|
4,585,020
|
|
|
$
|
3,429,570
|
|
Unevaluated properties
|
|
1,404,513
|
|
|
1,168,016
|
|
Total oil and natural gas properties
|
|
5,989,533
|
|
|
4,597,586
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
(2,270,675
|
)
|
|
(2,084,095
|
)
|
Total oil and natural gas properties capitalized
|
|
$
|
3,718,858
|
|
|
$
|
2,513,491
|
|
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Acquisition costs:
|
|
|
|
|
|
|
Evaluated properties
|
|
$
|
347,305
|
|
|
$
|
156,340
|
|
|
$
|
228,832
|
|
Unevaluated properties
|
|
466,816
|
|
|
499,295
|
|
|
536,540
|
|
Development costs
|
|
259,410
|
|
|
148,254
|
|
|
111,065
|
|
Exploration costs
|
|
323,458
|
|
|
239,453
|
|
|
38,612
|
|
Total costs incurred
|
|
$
|
1,396,989
|
|
|
$
|
1,043,342
|
|
|
$
|
915,049
|
|
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, 2018
. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
Average 12-month price, net of differentials, per barrel of oil
(a)
|
|
$
|
58.40
|
|
|
$
|
49.48
|
|
|
$
|
40.03
|
|
Average 12-month price, net of differentials, per Mcf of natural gas
(b)
|
|
$
|
3.64
|
|
|
$
|
3.47
|
|
|
$
|
2.71
|
|
|
|
(a)
|
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
|
|
|
(b)
|
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.
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
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,
|
|
|
2018
|
|
2017
|
|
2016
|
Future cash inflows
|
|
$
|
11,794,080
|
|
|
$
|
5,920,328
|
|
|
$
|
3,180,005
|
|
Future costs
|
|
|
|
|
|
|
Production
|
|
(2,923,959
|
)
|
|
(1,692,871
|
)
|
|
(974,667
|
)
|
Development and net abandonment
|
|
(1,429,787
|
)
|
|
(680,948
|
)
|
|
(384,117
|
)
|
Future net inflows before income taxes
|
|
7,440,334
|
|
|
3,546,509
|
|
|
1,821,221
|
|
Future income taxes
(a)
|
|
(782,470
|
)
|
|
(166,985
|
)
|
|
(1,602
|
)
|
Future net cash flows
|
|
6,657,864
|
|
|
3,379,524
|
|
|
1,819,619
|
|
10% discount factor
|
|
(3,716,571
|
)
|
|
(1,822,842
|
)
|
|
(1,009,787
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,941,293
|
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
|
(a)
|
As of
December 31, 2018
,
2017
, and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Standardized measure at the beginning of the period
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
$
|
570,890
|
|
Sales and transfers, net of production costs
|
|
(481,306
|
)
|
|
(294,172
|
)
|
|
(150,628
|
)
|
Net change in sales and transfer prices, net of production costs
|
|
222,802
|
|
|
176,234
|
|
|
(103,136
|
)
|
Net change due to purchases and sales of in place reserves
|
|
554,697
|
|
|
129,454
|
|
|
260,859
|
|
Extensions, discoveries, and improved recovery, net of future production and development costs incurred
|
|
1,093,773
|
|
|
635,000
|
|
|
180,228
|
|
Changes in future development cost
|
|
40,483
|
|
|
36,983
|
|
|
82,320
|
|
Revisions of quantity estimates
|
|
(167,096
|
)
|
|
(79,325
|
)
|
|
(35,938
|
)
|
Accretion of discount
|
|
157,676
|
|
|
80,983
|
|
|
57,091
|
|
Net change in income taxes
|
|
(187,841
|
)
|
|
(20,073
|
)
|
|
16
|
|
Changes in production rates, timing and other
|
|
151,423
|
|
|
81,766
|
|
|
(51,870
|
)
|
Aggregate change
|
|
1,384,611
|
|
|
746,850
|
|
|
238,942
|
|
Standardized measure at the end of period
|
|
$
|
2,941,293
|
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Supplemental Quarterly Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
127,440
|
|
|
$
|
137,075
|
|
|
$
|
161,214
|
|
|
$
|
161,895
|
|
Income from operations
|
|
60,986
|
|
|
67,400
|
|
|
72,811
|
|
|
58,333
|
|
Net income
|
|
55,761
|
|
|
50,474
|
|
|
37,931
|
|
|
156,194
|
|
Income available to common shares
|
|
53,937
|
|
|
48,650
|
|
|
36,108
|
|
|
154,370
|
|
Income per common share - basic
|
|
$
|
0.27
|
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.68
|
|
Income per common share - diluted
|
|
$
|
0.27
|
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
81,363
|
|
|
$
|
82,283
|
|
|
$
|
84,614
|
|
|
$
|
118,214
|
|
Income from operations
|
|
32,249
|
|
|
23,743
|
|
|
31,426
|
|
|
54,028
|
|
Net income
|
|
47,129
|
|
|
33,390
|
|
|
17,081
|
|
|
22,824
|
|
Income available to common shares
|
|
45,305
|
|
|
31,566
|
|
|
15,257
|
|
|
21,001
|
|
Income per common share - basic
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
Income per common share - diluted
|
|
$
|
0.22
|
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|