Note 1 - Description of Business and Basis of Presentation
Description of business
Callon is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. 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.
The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford Shale, which the Company entered into through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. The Company’s primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford Shale.
Basis of presentation
The accompanying unaudited interim consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and have been prepared pursuant to the rules and regulations of the SEC and therefore do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). In the opinion of management, these financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim financial position, results of operations and cash flows. However, the results of operations for the periods presented are not necessarily indicative of the results of operations that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period financial statements. However, the comparability of certain 2020 amounts to prior periods could be impacted as a result of the Carrizo Acquisition in December 2019.
Significant Accounting Policies
The Company’s significant accounting policies are described in “Note 2. Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2019 (“2019 Annual Report”) and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2019 Annual Report.
Three-stream reporting. Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with the Carrizo Acquisition, as defined below, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
See “Note 2 - Revenue Recognition” for additional information regarding the impact of three-stream reporting on our current results.
Recently Adopted Accounting Standards
None that had a material impact on our financial statements.
Recently Issued Accounting Pronouncements
Income Taxes. In December 2019, the FASB released Accounting Standards Update No. 2019-12 (ASU 2019-12): Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. We do not expect the adoption of this standard to have a material impact on our financial statements.
Subsequent Events
The Company evaluates subsequent events through the date the financial statements are issued. See “Note 15 - Subsequent Events” for further discussion.
Note 2 - 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
Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. We evaluate whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that we maintain control through processing or we have the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. These changes impact the comparability of 2020 with prior periods. For the three and six months ended June 30, 2019, $2.8 million and $5.2 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.
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 June 30, 2020 and December 31, 2019 of $74.6 million and $165.3 million, respectively, are presented in “Accounts receivable, net” in 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 utilized the practical expedient in ASC 606, 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.
Note 3 - Acquisitions and Divestitures
2020 Acquisitions and Divestitures
The Company did not have any material acquisitions or divestitures for the six months ended June 30, 2020.
2019 Acquisitions and Divestitures
Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes.
The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk-adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
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Preliminary Purchase
Price Allocation
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(In thousands)
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Consideration:
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Fair value of the Company’s common stock issued
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$765,373
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Total consideration
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$765,373
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Liabilities:
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Accounts payable
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$37,657
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Revenues and royalties payable
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52,449
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Operating lease liabilities - current
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29,924
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Fair value of derivatives - current
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61,015
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Other current liabilities
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88,627
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Long-term debt
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1,984,135
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Operating lease liabilities - non-current
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30,070
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Asset retirement obligation
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26,151
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Fair value of derivatives - non-current
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26,960
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Other long-term liabilities
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17,260
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Common stock warrants
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10,029
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Total liabilities assumed
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$2,364,277
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Assets:
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Accounts receivable, net
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$48,479
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Fair value of derivatives - current
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17,451
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Other current assets
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11,137
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Evaluated oil and natural gas properties
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2,133,280
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Unevaluated properties
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683,366
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Other property and equipment
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9,614
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Fair value of derivatives - non-current
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4,518
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Deferred tax asset
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159,320
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Operating lease right-of-use-assets
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59,907
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Other long term assets
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2,578
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Total assets acquired
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$3,129,650
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Approximately $86.9 million and $248.3 million of revenues and $47.7 million and $99.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the three and six months ended June 30, 2020, respectively.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.
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For the Year Ended
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December 31, 2019
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(In thousands)
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Revenues
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$1,620,357
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Income from operations
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614,668
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Net income
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369,777
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Basic earnings per common share
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0.89
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Diluted earnings per common share
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0.89
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During the three and six months ended June 30, 2020, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $8.1 million and $23.9 million, respectively, comprised of severance costs of $2.4 million and $5.4 million, respectively, and other merger and integration expenses of $5.7 million and $18.5 million, respectively. Through June 30, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $98.3 million comprised of severance costs of $34.2 million and other merger and integration expenses of $64.1 million. As of June 30, 2020, $23.0 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized.
Note 4 - Property and Equipment, Net
As of June 30, 2020 and December 31, 2019, total property and equipment, net consisted of the following:
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June 30, 2020
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December 31, 2019
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Oil and natural gas properties, full cost accounting method
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(In thousands)
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Evaluated properties
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$7,840,616
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$7,203,482
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Accumulated depreciation, depletion, amortization and impairments
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(4,062,660)
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(2,520,488)
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Net evaluated oil and natural gas properties
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3,777,956
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4,682,994
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Unevaluated properties
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Unevaluated leasehold and seismic costs
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1,596,662
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1,843,725
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Capitalized interest
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166,198
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142,399
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Total unevaluated properties
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1,762,860
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1,986,124
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Total oil and natural gas properties, net
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$5,540,816
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$6,669,118
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Other property and equipment
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$67,883
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$67,202
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Accumulated depreciation
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(35,439)
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(31,949)
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Other property and equipment, net
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$32,444
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$35,253
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The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $8.9 million and $8.4 million for the three months ended June 30, 2020 and 2019, respectively, and $16.4 million and $19.1 million for the six months ended June 30, 2020 and 2019.
The Company capitalized interest costs associated with its unproved properties totaling $20.9 million and $18.7 million for the three months ended June 30, 2020 and 2019, respectively, and $44.9 million and $38.6 million for the six months ended June 30, 2020 and 2019.
As a result of the recent downturn in the oil and gas industry as well as in the broader macroeconomic environment, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. The Company transferred $43.9 million and $224.4 million from unevaluated leasehold to evaluated properties during the three and six months ended June 30, 2020, respectively, primarily as a result of the analysis described above.
Impairment of Evaluated Oil and Gas Properties
Primarily due to declines in the average realized prices for sales of oil on the first calendar day of each month during the trailing 12-month period (“12-Month Average Realized Price”) prior to June 30, 2020, the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in an impairment in the carrying value of evaluated oil and gas properties for the three months ended June 30, 2020. An impairment of evaluated oil and gas properties recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices in the future increase the cost center ceiling applicable to the subsequent period. There were no impairments of evaluated oil and gas properties for the three months ended March 31, 2020 or for the corresponding prior year periods.
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Three Months Ended June 30,
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2020
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2019
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Impairment of evaluated oil and gas properties (in thousands)
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$1,276,518
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$—
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Beginning of period 12-Month Average Realized Price ($/Bbl)
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$54.63
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$54.58
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End of period 12-Month Average Realized Price ($/Bbl)
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$45.87
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$53.00
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Percent decrease in 12-Month Average Realized Price
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(16
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%)
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(3
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%)
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The Company expects to record an additional impairment in the carrying value of evaluated oil and gas properties in the third quarter of 2020 based on an estimated 12-Month Average Realized price of crude oil of approximately $43.45 as of September 30, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties.
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 per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the three and six months ended June 30, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded the anti-dilutive effect of 9.1 million and 9.2 million potentially dilutive common shares outstanding for the three and six months ended June 30, 2020, respectively. The following table sets forth the computation of basic and diluted earnings per share:
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Three Months Ended June 30,
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Six Months Ended June 30,
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2020
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2019
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2020
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2019
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(In thousands, except per share amounts)
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Net income (loss)
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($1,564,731)
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$55,180
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($1,348,166)
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$35,637
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Preferred stock dividends (1)
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—
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(1,823)
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—
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(3,647)
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Income (loss) available to common stockholders
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($1,564,731)
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$53,357
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($1,348,166)
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$31,990
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Basic weighted average common shares outstanding
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397,084
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228,051
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396,884
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227,917
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Dilutive impact of restricted stock
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—
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360
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—
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682
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Diluted weighted average common shares outstanding
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397,084
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228,411
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396,884
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228,599
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Income (Loss) Available to Common Stockholders Per Common Share
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Basic
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($3.94)
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$0.23
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($3.40)
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$0.14
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Diluted
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($3.94)
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$0.23
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($3.40)
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$0.14
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Restricted stock (2)
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9,066
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641
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9,169
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|
498
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(1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.
(2) 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:
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June 30, 2020
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December 31, 2019
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(In thousands)
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Senior Secured Revolving Credit Facility due 2024
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$1,450,000
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$1,285,000
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6.25% Senior Notes due 2023
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650,000
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650,000
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6.125% Senior Notes due 2024
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600,000
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600,000
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8.25% Senior Notes due 2025
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250,000
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250,000
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6.375% Senior Notes due 2026
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400,000
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400,000
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Total principal outstanding
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3,350,000
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3,185,000
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Unamortized premium on 6.125% Senior Notes
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4,781
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5,344
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Unamortized premium on 6.25% Senior Notes
|
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4,163
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|
4,838
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Unamortized premium on 8.25% Senior Notes
|
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4,809
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5,286
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Unamortized deferred financing costs for Senior Notes
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(13,023)
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(14,359)
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Total carrying value of borrowings (1)
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$3,350,730
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$3,186,109
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(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $26.0 million and $22.2 million as of June 30, 2020 and December 31, 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior secured revolving credit facility
The Company has a senior secured revolving credit facility with a syndicate of lenders that, as of June 30, 2020, had a borrowing base of $1.7 billion, with an elected commitment amount of $1.7 billion, borrowings outstanding of $1.45 billion at a weighted-average interest rate of 3.01%, and letters of credit outstanding of $19.7 million. The credit agreement governing the revolving credit facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25%
Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The revolving credit facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.
On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the revolving credit facility. The amendment, among other things, (a) establishes a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduces the elected commitments to $1.7 billion; (b) permits the incurrence of, among other things, new second lien notes exchanged for unsecured notes in an aggregate principal amount of up to $400 million (the “Second Lien Notes”) so long as any such Second Lien Notes are subject to an intercreditor agreement providing that the liens securing the Second Lien Notes rank junior to the liens securing the credit agreement; (c) provides that testing of the Leverage Ratio, which is the ratio of consolidated total debt to Adjusted EBITDAX on a quarterly basis is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; (d) provides a new financial covenant testing the Secured Leverage Ratio, which is the ratio of the consolidated total secured debt to Adjusted EBITDAX and provides that such ratio on a quarterly basis as of the last day of each quarter beginning with March 31, 2020 up to and including the quarter ending December 31, 2021 may not exceed 3.00 to 1.00; (e) provides that the testing of the Current Ratio, which is the ratio of current assets to current liabilities is suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00; (f) increases the applicable margins for borrowings under the credit agreement for both LIBOR loans and base rate loans by 75 basis points across all commitment utilization ranges; (g) introduces customary anti-cash hoarding protections tested weekly, which restrict the Company’s ability to maintain unrestricted cash on its balance sheet in amounts in the excess of the lesser of (i) $125.0 million or (ii) 7.5% of the then current borrowing base; (h) requires the Company to enter into and maintain minimum hedges for the 12 month period starting January 1, 2021 through December 31, 2021, for which the net notional volumes on a barrel of oil equivalent basis are not less than 40% of the reasonably anticipated production from the Company’s oil and gas properties which are classified as proved developed producing reserves as of April 1, 2020; (i) requires mortgage and title coverage on at least 90% of the total value of proved oil and gas properties evaluated in the most recently delivered reserve report; and (j) restricts the Company’s ability to make certain investments and cash distributions by lowering the maximum leverage ratio required to make such distributions to 2.50 to 1.00.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00% to 2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00% to 3.00%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations.
Restrictive covenants
The Company’s credit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio recommencing September 30, 2020, of not less than 1.00 to 1.00. The Company was in compliance with these covenants at June 30, 2020.
The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement is subject to customary events of default. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 7 - Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil, natural gas and NGL 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, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options 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 Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. 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.
As of June 30, 2020, the Company has outstanding commodity derivative instruments with fifteen counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
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 - Fair Value Measurements” for further discussion.
Financial statement presentation and settlements
Settlements of the Company’s commodity 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 - Fair Value Measurements” for additional information regarding fair value.
Contingent consideration arrangements
Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds in each of the next several years. See “Note 3 - Acquisitions and Divestitures” and “Note 8 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):
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Year
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Threshold (1)
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|
Contingent Receipt - Annual
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|
Threshold (1)
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|
Contingent Receipt - Annual
|
|
Period Cash Flow Occurs
|
|
Statement of Cash Flows Presentation
|
|
Remaining Contingent Receipt - Aggregate Limit (3)
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Divestiture Date Fair Value
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$8,512
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Actual Settlement
|
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2019
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Greater than $60/Bbl, less than $65/Bbl
|
|
$—
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Equal to or greater than $65/Bbl
|
|
$—
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1Q20
|
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N/A
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Remaining Potential Settlements
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2020-2021
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Greater than $60/Bbl, less than $65/Bbl
|
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$9,000
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Equal to or greater than $65/Bbl
|
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$20,833
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(2)
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(2)
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$41,666
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(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.
(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.
(3) The specified pricing threshold for 2019 was not met. As such, approximately $41.7 million remains for potential settlements in future years.
As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:
Contingent ExL Consideration
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Year
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Threshold (1)
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Period
Cash Flow
Occurs
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Statement of
Cash Flows Presentation
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Contingent
Payment -
Annual
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Remaining Contingent
Payments -
Aggregate Limit
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Acquisition
Date
Fair Value
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(In thousands)
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($69,171)
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Actual Settlement(2)(3)
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2019
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$50.00
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1Q20
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Investing
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($50,000)
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Remaining Potential Settlements
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2020-2021
|
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$50.00
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(2)
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(2)
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($25,000)
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($25,000)
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(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).
(2) Cash paid for settlements related to 2019 are classified as cash flows used in investing activities as the cash payment was made soon after the acquisition date. Due to the extended time frame over which the 2020 and 2021 contingent arrangements could settle, any future payments would be considered financing arrangements. As such, cash settlements of those contingent consideration arrangements would be classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold were reached, $19.2 million of the final contingent payment would be presented in cash flows used in financing activities with the remainder presented in operating cash flows.
(3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.
Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met in 2020, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020.
Derivatives not designated as hedging instruments
The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) 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. As previously discussed, the Company’s commodity 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 sheets. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
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|
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As of June 30, 2020
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Presented without
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As Presented with
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|
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Effects of Netting
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Effects of Netting
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Effects of Netting
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ASSETS
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(In thousands)
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Commodity derivative instruments
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$63,380
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($31,890)
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$31,490
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Contingent consideration arrangements
|
73
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|
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—
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73
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|
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Fair value of derivatives - current
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$63,453
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|
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($31,890)
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|
|
$31,563
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Commodity derivative instruments
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1,404
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|
|
(952)
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|
|
452
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|
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Contingent consideration arrangements
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1,234
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|
|
—
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1,234
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Other assets, net
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$2,638
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($952)
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|
|
$1,686
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LIABILITIES
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Commodity derivative instruments
|
($64,122)
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|
|
$31,890
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|
|
($32,232)
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|
|
Contingent consideration arrangements
|
(451)
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|
|
—
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|
|
(451)
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|
Fair value of derivatives - current
|
($64,573)
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|
|
$31,890
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|
|
($32,683)
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|
|
Commodity derivative instruments
|
(6,518)
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|
|
952
|
|
|
(5,566)
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|
Contingent consideration arrangements
|
(3,112)
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|
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—
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|
|
(3,112)
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Fair value of derivatives - non current
|
($9,630)
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|
|
$952
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|
|
($8,678)
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|
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|
|
As of December 31, 2019
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|
|
Presented without
|
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|
|
As Presented with
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|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
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ASSETS
|
(In thousands)
|
|
|
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|
|
Commodity derivative instruments
|
$26,849
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|
|
($17,511)
|
|
|
$9,338
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|
|
Contingent consideration arrangements
|
16,718
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|
|
—
|
|
|
16,718
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|
|
Fair value of derivatives - current
|
$43,567
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|
|
($17,511)
|
|
|
$26,056
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|
|
Commodity derivative instruments
|
—
|
|
|
—
|
|
|
—
|
|
|
Contingent consideration arrangements
|
9,216
|
|
|
—
|
|
|
9,216
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|
|
Other assets, net
|
$9,216
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|
|
$—
|
|
|
$9,216
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|
|
LIABILITIES
|
|
|
|
|
|
|
Commodity derivative instruments
|
($38,708)
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|
|
$17,511
|
|
|
($21,197)
|
|
|
Contingent consideration arrangements
|
(50,000)
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|
|
—
|
|
|
(50,000)
|
|
|
Fair value of derivatives - current
|
($88,708)
|
|
|
$17,511
|
|
|
($71,197)
|
|
|
Commodity derivative instruments
|
(12,935)
|
|
|
—
|
|
|
(12,935)
|
|
|
Contingent consideration arrangements
|
(19,760)
|
|
|
—
|
|
|
(19,760)
|
|
|
Fair value of derivatives - non current
|
($32,695)
|
|
|
$—
|
|
|
($32,695)
|
|
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
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|
|
Three Months Ended June 30,
|
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|
|
Six Months Ended June 30,
|
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|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
(Gain) loss on oil derivatives
|
$122,369
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|
|
($8,849)
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|
|
($134,954)
|
|
|
$59,520
|
|
|
(Gain) loss on natural gas derivatives
|
4,695
|
|
|
(1,874)
|
|
|
11,524
|
|
|
(2,983)
|
|
|
Gain on NGL derivatives
|
(4)
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
Gain on contingent consideration arrangements
|
(95)
|
|
|
(3,313)
|
|
|
(1,570)
|
|
|
(3,313)
|
|
|
(Gain) loss on derivative contracts
|
$126,965
|
|
|
($14,036)
|
|
|
($125,004)
|
|
|
$53,224
|
|
The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Cash (paid) received on oil derivatives
|
$100,470
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|
|
($4,461)
|
|
|
$98,693
|
|
|
($6,003)
|
|
|
Cash (paid) received on natural gas derivatives
|
(1,782)
|
|
|
3,304
|
|
|
2,608
|
|
|
4,556
|
|
|
Cash (paid) received for commodity derivative settlements
|
$98,688
|
|
|
($1,157)
|
|
|
$101,301
|
|
|
($1,447)
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Cash paid for settlements of contingent consideration arrangements, net
|
$—
|
|
|
$—
|
|
|
($40,000)
|
|
|
$—
|
|
Derivative positions
Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of June 30, 2020:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
|
|
|
For the Full Year
|
|
|
|
|
|
Oil contracts (WTI)
|
of 2020
|
|
|
of 2021
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
6,291,880
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$42.08
|
|
|
|
$—
|
|
|
|
|
|
|
Collar contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
2,863,040
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
|
|
|
Ceiling (short call)
|
$45.00
|
|
|
|
$—
|
|
|
|
|
|
|
Floor (long put)
|
$35.00
|
|
|
|
$—
|
|
|
|
|
|
|
Short put contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
1,104,000
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$42.50
|
|
|
|
$—
|
|
|
|
|
|
|
Long call contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
920,000
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$67.50
|
|
|
|
$—
|
|
|
|
|
|
|
Short call contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
920,000
|
|
(1)
|
|
4,825,300
|
|
(1)
|
|
|
|
|
Weighted average price per Bbl
|
$55.00
|
|
|
|
$63.62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (WTI Calendar Month Average Roll)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
3,864,000
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
($2.75)
|
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (Brent ICE)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
184,000
|
|
|
|
1,272,450
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$46.15
|
|
|
|
$38.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
4,609,200
|
|
|
|
4,015,100
|
|
|
|
|
|
|
Weighted average price per Bbl
|
($0.98)
|
|
|
|
$0.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (Argus Houston MEH basis differential)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
3,256,004
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$0.06
|
|
|
|
$—
|
|
|
|
|
|
|
Oil contracts (Argus Houston MEH swaps)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
368,000
|
|
|
|
2,969,050
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$57.71
|
|
|
|
$39.48
|
|
|
|
|
|
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
|
|
|
For the Full Year
|
|
|
|
|
|
Natural gas contracts (Henry Hub)
|
of 2020
|
|
|
of 2021
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
5,530,000
|
|
|
|
12,923,000
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
$2.21
|
|
|
|
$2.66
|
|
|
|
|
|
|
Collar contracts (three-way collars)
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
2,755,000
|
|
|
|
1,350,000
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
|
|
|
Ceiling (short call)
|
$2.73
|
|
|
|
$2.70
|
|
|
|
|
|
|
Floor (long put)
|
$2.47
|
|
|
|
$2.42
|
|
|
|
|
|
|
Floor (short put)
|
$2.00
|
|
|
|
$2.00
|
|
|
|
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
1,525,000
|
|
|
|
7,750,000
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
|
|
|
Ceiling (short call)
|
$3.25
|
|
|
|
$2.93
|
|
|
|
|
|
|
Floor (long put)
|
$2.67
|
|
|
|
$2.55
|
|
|
|
|
|
|
Short call contracts
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
6,072,000
|
|
|
|
7,300,000
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
$3.50
|
|
|
|
$3.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
12,885,000
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
($0.92)
|
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
|
|
|
For the Full Year
|
|
|
|
|
|
NGL contracts (OPIS Mont Belvieu Purity Ethane)
|
of 2020
|
|
|
of 2021
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
|
1,825,000
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$—
|
|
|
|
$7.62
|
|
|
|
|
|
See “Note 15 - Subsequent Events” for additional information regarding derivative contracts entered into subsequent to June 30, 2020.
Note 8 - Fair Value Measurements
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
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 borrowings outstanding under the Credit Facility approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior notes
with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 6 - Borrowings” for further discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
|
|
December 31, 2019
|
|
|
|
|
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
6.25% Senior Notes
|
|
$650,000
|
|
|
$240,500
|
|
|
$650,000
|
|
|
$658,125
|
|
|
6.125% Senior Notes
|
|
600,000
|
|
|
216,000
|
|
|
600,000
|
|
|
611,130
|
|
|
8.25% Senior Notes
|
|
250,000
|
|
|
87,500
|
|
|
250,000
|
|
|
256,250
|
|
|
6.375% Senior Notes
|
|
400,000
|
|
|
136,000
|
|
|
400,000
|
|
|
405,424
|
|
|
Total
|
|
$1,900,000
|
|
|
$680,000
|
|
|
$1,900,000
|
|
|
$1,930,929
|
|
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 a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 7 - Derivative Instruments and Hedging Activities” for further discussion.
Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 7 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
$—
|
|
|
$31,942
|
|
|
$—
|
|
|
Contingent consideration arrangements
|
—
|
|
|
1,307
|
|
|
—
|
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
—
|
|
|
(37,798)
|
|
|
—
|
|
|
Contingent consideration arrangements
|
—
|
|
|
(3,563)
|
|
|
—
|
|
|
Total net assets (liabilities)
|
$—
|
|
|
($8,112)
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
$—
|
|
|
$9,338
|
|
|
$—
|
|
|
Contingent consideration arrangements
|
—
|
|
|
25,934
|
|
|
—
|
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
—
|
|
|
(34,132)
|
|
|
—
|
|
|
Contingent consideration arrangements
|
—
|
|
|
(69,760)
|
|
|
—
|
|
|
Total net assets (liabilities)
|
$—
|
|
|
($68,620)
|
|
|
$—
|
|
Assets and liabilities measured at fair value on a nonrecurring basis
Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and
market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk-adjusted discount rate. See “Note 3 - Acquisitions and Divestitures” for additional discussion.
Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates.
Note 9 - Income Taxes
The Company provides for income taxes at the 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
Income tax expense computed at the statutory federal income tax rate
|
21
|
%
|
|
21
|
%
|
|
21
|
%
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
State taxes net of federal expense
|
1
|
%
|
|
1
|
%
|
|
1
|
%
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
Section 162(m)
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate, before discrete items
|
22
|
%
|
|
22
|
%
|
|
22
|
%
|
|
22
|
%
|
|
Valuation allowance
|
(25
|
%)
|
|
—
|
%
|
|
(31
|
%)
|
|
—
|
%
|
|
Other discrete items (1)
|
—
|
%
|
|
1
|
%
|
|
—
|
%
|
|
2
|
%
|
|
Effective income tax rate, after discrete items
|
(3
|
%)
|
|
23
|
%
|
|
(9
|
%)
|
|
24
|
%
|
(1) Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that
the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at June 30, 2020, driven primarily by the impairment of evaluated oil and gas properties recognized for the three months ended June 30, 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Based on the evaluation of the evidence available during the three months ended June 30, 2020, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized and recorded a valuation allowance of $377.6 million, reducing the net deferred tax assets as of June 30, 2020 to zero.
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Note 10 - Share-based Compensation
Stock-Based Compensation Plans
At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “Prior Incentive Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. The 2020 Plan provides that up to 13,250,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan, may be issued. As of June 30, 2020, there were 15,937,327 common shares remaining available for grant under the 2020 Plan.
RSU Equity Awards
The following table summarizes activity for restricted stock units may be settled in common stock (“RSU Equity Awards”) for the three and six months ended June 30, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
|
|
RSU Equity Awards
(in thousands)
|
|
Weighted Average Grant Date
Fair Value
|
|
RSU Equity Awards
(in thousands)
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested, beginning of the period
|
|
4,851
|
|
|
$6.95
|
|
|
3,406
|
|
|
$11.14
|
|
|
Granted (1)
|
|
3,257
|
|
|
$1.26
|
|
|
171
|
|
|
$7.87
|
|
|
Vested (2)
|
|
(900)
|
|
|
$10.06
|
|
|
(458)
|
|
|
$12.51
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
(64)
|
|
|
$11.43
|
|
|
Unvested, end of the period
|
|
7,208
|
|
|
$3.99
|
|
|
3,055
|
|
|
$10.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
|
|
RSU Equity Awards
(in thousands)
|
|
Weighted Average Grant Date
Fair Value
|
|
RSU Equity Awards
(in thousands)
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested, beginning of the period
|
|
2,695
|
|
|
$10.25
|
|
|
2,103
|
|
|
$13.24
|
|
|
Granted (1)
|
|
5,575
|
|
|
$2.12
|
|
|
1,881
|
|
|
$8.60
|
|
|
Vested (2)
|
|
(1,062)
|
|
|
$10.02
|
|
|
(791)
|
|
|
$12.23
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
(138)
|
|
|
$10.82
|
|
|
Unvested, end of the period
|
|
7,208
|
|
|
$3.99
|
|
|
3,055
|
|
|
$10.75
|
|
(1)Includes 0.3 million and zero target performance-based RSU Equity Awards during the three months ended June 30, 2020 and 2019, respectively, and 1.1 million and 0.4 million during the six months ended June 30, 2020 and 2019, respectively. The awards granted during the six months ended June 30, 2020 and 2019 will vest at a range of 0% to 300% and 0% to 200%, respectively.
(2)The fair value of shares vested was $0.6 million and $3.4 million during the three months ended June 30, 2020 and 2019, respectively, and $1.3 million and $6.0 million for the six months ended June 30, 2020 and 2019, respectively.
Grant activity for the six months ended June 30, 2020 and 2019 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards in January and June 2020, respectively, as compared to the annual grant of long-term equity to executives and employees during the first quarter of 2019.
The number of outstanding performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units for the awards granted in 2020 and between 0% and 200% of the target units for the awards granted in 2018 and 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5% over the performance period.
The Company recognizes expense for performance-based RSU Equity Awards 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. The grant date fair value of performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $0.5 million and zero for the three months ended June 30, 2020 and 2019, respectively, and $3.4 million and $4.3 million for the six months ended June 30, 2020 and 2019, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the six months ended June 30, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance-based Awards
|
|
June 29, 2020
|
|
January 31, 2020
|
|
January 31, 2019
|
|
Expected term (in years)
|
|
2.5
|
|
2.9
|
|
2.9
|
|
Expected volatility
|
|
113.2
|
%
|
|
54.8
|
%
|
|
47.9
|
%
|
|
Risk-free interest rate
|
|
0.2
|
%
|
|
1.3
|
%
|
|
2.4
|
%
|
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Grant date fair value per performance-based RSU Equity Award
|
|
$1.80
|
|
$3.39
|
|
$10.78
|
As of June 30, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $19.7 million and will be recognized over a weighted average period of 2.1 years.
Cash-Settled RSU Awards
The table below summarizes the activity for restricted stock units that may be settled in cash (“Cash-Settled RSU Awards”) for the three and six months ended June 30, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
|
|
Cash-Settled RSU Awards
(in thousands)
|
|
Weighted Average Grant Date
Fair Value
|
|
Cash-Settled RSU Awards
(in thousands)
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested, beginning of the period
|
|
1,707
|
|
|
$7.85
|
|
|
1,044
|
|
|
$11.69
|
|
|
Granted
|
|
386
|
|
|
$2.03
|
|
|
25
|
|
|
$8.1
|
|
|
Vested
|
|
(2)
|
|
|
$16.66
|
|
|
(17)
|
|
|
$11.06
|
|
|
Did not vest at end of performance period
|
|
(11)
|
|
|
$15.27
|
|
|
—
|
|
|
$—
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
(21)
|
|
|
$16.38
|
|
|
Unvested, end of the period
|
|
2,080
|
|
|
$6.72
|
|
|
1,031
|
|
|
$11.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
2019
|
|
|
|
|
|
Cash-Settled RSU Awards
(in thousands)
|
|
Weighted Average Grant Date
Fair Value
|
|
Cash-Settled RSU Awards
(in thousands)
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested, beginning of the period
|
|
855
|
|
|
$12.42
|
|
|
678
|
|
|
$12.36
|
|
|
Granted
|
|
1,249
|
|
|
$2.98
|
|
|
424
|
|
|
$10.62
|
|
|
Vested
|
|
(12)
|
|
|
$12.85
|
|
|
(17)
|
|
|
$11.06
|
|
|
Did not vest at end of performance period
|
|
(12)
|
|
|
$16.66
|
|
|
—
|
|
|
$—
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
(54)
|
|
|
$15.21
|
|
|
Unvested, end of the period
|
|
2,080
|
|
|
$6.72
|
|
|
1,031
|
|
|
$11.52
|
|
Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. These awards cliff vest after an approximate three-year performance period.
The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used and the resulting grant date fair value per Cash-Settled RSU Award granted for each of the respective periods presented are the same as the performance-based RSU Equity Awards presented above.
The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
December 31, 2019
|
|
|
|
(In thousands)
|
|
|
|
Other current liabilities
|
|
$231
|
|
|
$966
|
|
|
Other long-term liabilities
|
|
674
|
|
|
2,089
|
|
|
Total Cash-Settled RSU Awards
|
|
$905
|
|
|
$3,055
|
|
As of June 30, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $2.2 million and will be recognized over a weighted average period of 2.3 years.
Share-Based Compensation Expense, Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and cash-settled stock appreciation rights (“Cash SARs”), net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
RSU Equity Awards
|
|
$3,212
|
|
|
$2,907
|
|
|
$7,160
|
|
|
$8,383
|
|
|
Cash-Settled RSU Awards
|
|
596
|
|
|
203
|
|
|
(1,400)
|
|
|
1,354
|
|
|
Cash SARs
|
|
1,115
|
|
|
—
|
|
|
(3,641)
|
|
|
—
|
|
|
|
|
4,923
|
|
|
3,110
|
|
|
$2,119
|
|
|
$9,737
|
|
|
Less: amounts capitalized to oil and gas properties
|
|
(2,162)
|
|
|
(1,131)
|
|
|
(2,330)
|
|
|
(2,304)
|
|
|
Total share-based compensation expense (benefit), net
|
|
$2,761
|
|
|
$1,979
|
|
|
($211)
|
|
|
$7,433
|
|
See “Note 10 - Stock-Based Compensation” of the Notes to Consolidated Financial Statements in the 2019 Annual Report for details of the Company’s equity-based incentive plans.
Note 11 - Leases
The Company determines if an arrangement is a lease at inception of the contract. If the contract is determined to be a lease the Company classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease. The Company also records a corresponding right-of-use (“ROU”) asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.
Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is also recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.
The majority of the lease liability on the Company’s consolidated balance sheets is comprised of its drilling rig and office lease contracts.
The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.
The table below presents the components of the Company’s lease costs for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Components of Lease Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Finance lease costs
|
$552
|
|
|
$—
|
|
|
$1,128
|
|
|
$—
|
|
|
|
|
|
|
Amortization of right-of-use assets (1)
|
510
|
|
|
—
|
|
|
1,020
|
|
|
—
|
|
|
|
|
|
|
Interest on lease liabilities (2)
|
42
|
|
|
—
|
|
|
108
|
|
|
—
|
|
|
|
|
|
|
Operating lease costs (3)
|
16,387
|
|
|
9,565
|
|
|
33,664
|
|
|
19,156
|
|
|
|
|
|
|
Impairment of Operating lease ROU assets (4)
|
1,982
|
|
|
—
|
|
|
3,575
|
|
|
—
|
|
|
|
|
|
|
Short-term lease costs (5)
|
38
|
|
|
1,849
|
|
|
1,726
|
|
|
3,347
|
|
|
|
|
|
|
Variable lease costs (6)
|
70
|
|
|
—
|
|
|
74
|
|
|
—
|
|
|
|
|
|
|
Total lease costs
|
$19,029
|
|
|
$11,414
|
|
|
$40,167
|
|
|
$22,503
|
|
|
|
|
|
(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations.
(2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
(3) For the three months ended June 30, 2020 and 2019, approximately $15.2 million and $7.0 million were costs associated with drilling rigs. For the six months ended June 30, 2020 and 2019, approximately $23.7 million and $13.9 million were costs associated with drilling rigs. and were capitalized to “Evaluated properties” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.
(4) As a result of the downturn in economic conditions in conjunction with our ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the three and six months ended June 30, 2020 of $2.0 million and $3.6 million which is a component of “Merger and integration expenses” in the consolidated statements of operations.
(5) Short-term lease costs exclude expenses related to leases with a contract term of one month or less.
(6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
The table below presents supplemental balance sheet information for the Company’s leases as of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
December 31, 2019
|
|
|
(In thousands)
|
|
|
|
Leases
|
|
|
|
|
Operating leases:
|
|
|
|
|
Operating lease ROU assets
|
$35,926
|
|
|
$63,908
|
|
|
|
|
|
|
|
Current operating lease liabilities
|
$24,355
|
|
|
$42,858
|
|
|
Long-term operating lease liabilities
|
30,729
|
|
|
37,088
|
|
|
Total operating lease liabilities
|
$55,084
|
|
|
$79,946
|
|
|
|
|
|
|
|
Financing leases:
|
|
|
|
|
Other property and equipment
|
$2,313
|
|
|
$2,197
|
|
|
Accumulated depreciation
|
(1,257)
|
|
|
(82)
|
|
|
Other property and equipment, net
|
$1,056
|
|
|
$2,115
|
|
|
|
|
|
|
|
Current financing lease liabilities
|
$463
|
|
|
$1,334
|
|
|
Long-term financing lease liabilities
|
572
|
|
|
807
|
|
|
Total financing lease liabilities
|
$1,035
|
|
|
$2,141
|
|
The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases for the period indicated:
|
|
|
|
|
|
|
|
|
As of June 30, 2020
|
|
Weighted Average Remaining Lease Term (In years)
|
|
|
Operating leases
|
5.4
|
|
Financing leases
|
2.8
|
|
|
|
|
Weighted Average Discount Rate
|
|
|
Operating leases
|
5.4
|
%
|
|
Financing leases
|
7.1
|
%
|
The table below presents the maturity of the Company’s lease liabilities as of June 30, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Financing Leases
|
|
|
(In thousands)
|
|
|
|
Remainder of 2020
|
$16,362
|
|
|
$363
|
|
|
2021
|
14,116
|
|
|
275
|
|
|
2022
|
5,453
|
|
|
234
|
|
|
2023
|
5,013
|
|
|
233
|
|
|
2024
|
4,937
|
|
|
38
|
|
|
Thereafter
|
18,097
|
|
|
—
|
|
|
Total lease payments
|
63,978
|
|
|
1,143
|
|
|
Less imputed interest
|
(8,894)
|
|
|
(108)
|
|
|
Total
|
$55,084
|
|
|
$1,035
|
|
Note 12 - Accounts Receivable, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
December 31, 2019
|
|
|
(In thousands)
|
|
|
|
Oil and natural gas receivables
|
$74,555
|
|
|
$165,275
|
|
|
Joint interest receivables
|
9,664
|
|
|
39,114
|
|
|
Other receivables
|
13,388
|
|
|
6,610
|
|
|
Total
|
97,607
|
|
|
210,999
|
|
|
Allowance for doubtful accounts
|
(1,768)
|
|
|
(1,536)
|
|
|
Total accounts receivable, net
|
$95,839
|
|
|
$209,463
|
|
Note 13 - Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020
|
|
December 31, 2019
|
|
|
(In thousands)
|
|
|
|
Accounts payable
|
$202,467
|
|
|
$238,758
|
|
|
Revenues payable
|
109,054
|
|
|
145,816
|
|
|
Accrued capital expenditures
|
29,926
|
|
|
61,950
|
|
|
Accrued interest
|
43,441
|
|
|
36,295
|
|
|
Accrued severance (1)
|
20,708
|
|
|
28,803
|
|
|
Total accounts payable and accrued liabilities
|
$405,596
|
|
|
$511,622
|
|
(1) See “Note 3 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.
Note 14 - Supplemental Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
2020
|
|
2019
|
|
Supplemental cash flow information:
|
|
|
|
|
Interest paid, net of capitalized amounts
|
$31,649
|
|
|
$—
|
|
|
Income taxes paid
|
—
|
|
|
—
|
|
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
|
|
|
Operating cash flows from operating leases
|
$26,110
|
|
|
$1,293
|
|
|
Investing cash flows from operating leases
|
11,278
|
|
|
17,865
|
|
|
Non-cash investing and financing activities:
|
|
|
|
|
Change in accrued capital expenditures
|
($6,186)
|
|
|
($16,286)
|
|
|
Change in asset retirement costs
|
207
|
|
|
—
|
|
|
ROU assets obtained in exchange for lease liabilities:
|
|
|
|
|
Operating leases
|
$2,666
|
|
|
$2,462
|
|
Note 15 - Subsequent Events
Hedging
Subsequent to June 30, 2020, the Company entered into the following derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
|
|
|
For the Full Year
|
|
|
|
|
|
Oil contracts (WTI)
|
of 2020
|
|
|
of 2021
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
|
1,377,000
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$—
|
|
|
|
$42.00
|
|
|
|
|
|
|
Collar contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
|
3,741,250
|
|
|
|
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
|
|
|
Ceiling (short call)
|
$—
|
|
|
|
$45.02
|
|
|
|
|
|
|
Floor (long put)
|
$—
|
|
|
|
$40.00
|
|
|
|
|
|
|
Short call swaption contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
|
730,000
|
|
(1)
|
|
|
|
|
Weighted average price per Bbl
|
$—
|
|
|
|
$47.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
|
|
|
|
|
Long swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (Bbls)
|
1,514,500
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per Bbl
|
$0.60
|
|
|
|
$—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts (Henry Hub)
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
3,036,000
|
|
|
|
—
|
|
|
|
|
|
|
Weighted average price per MMBtu
|
$1.80
|
|
|
|
$—
|
|
|
|
|
|
|
Long call contracts
|
|
|
|
|
|
|
|
|
|
Total volume (MMBtu)
|
3,036,000
|
|
|
|
—
|
|
|
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Weighted average price per MMBtu
|
$3.50
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|
$—
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Natural gas contracts (Waha basis differential)
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Swap contracts
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Total volume (MMBtu)
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—
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6,387,500
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Weighted average price per MMBtu
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$—
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|
|
|
($0.58)
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(1) The short call swaption contract has an exercise expiration date of October 30, 2020.
Reverse Stock Split
On August 4, 2020, the Company announced that its Board of Directors approved a reverse stock split of Company’s outstanding shares of common stock at a ratio of 1-for-10 and a proportionate reduction of the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split will become effective as of the close of business on August 7, 2020 and the Company’s common stock will begin trading on a split-adjusted basis on the NYSE at market open on August 10, 2020. The par value of the common stock will not be adjusted in connection with the reverse stock split.
The reverse stock split is intended to, among other things, increase the per share trading price of the Company’s common shares to maintain compliance with the $1.00 minimum closing price requirement for continued listing on the NYSE and improve the opportunity for institutional ownership. Upon completion of the reverse stock split, each 10 pre-split shares of common stock outstanding will be automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled, and shareholders who would otherwise hold fractional shares as a result of the reverse stock split will be entitled to receive cash (without interest and subject to applicable withholding taxes) in lieu of such fractional shares. The number of outstanding shares of common stock will be reduced from approximately 397,476,674 as of July 31, 2020 to approximately 39,747,667 shares (without giving effect to the liquidation of fractional shares). The total number of shares of common stock that the Company is authorized to issue will be reduced from 525,000,000 to 52,500,000 shares.
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
•matters relating to the Carrizo Acquisition;
•our oil and natural gas reserve quantities, and the discounted present value of these reserves;
•the amount and nature of our capital expenditures;
•our future drilling and development plans and our potential drilling locations;
•the timing and amount of future capital and operating costs;
•production decline rates from our wells being greater than expected;
•commodity price risk management activities and the impact on our average realized prices;
•business strategies and plans of management;
•our ability to consummate and efficiently integrate recent acquisitions; and
•prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:
•volatility of oil, natural gas and natural gas liquids (“NGLs”) prices or a prolonged period of low oil, natural gas or NGLs prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;
•general economic conditions including the availability of credit and access to existing lines of credit;
•the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
•the uncertainty of estimates of oil and natural gas reserves;
•impairments;
•the impact of competition;
•the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;
•operating hazards inherent in the exploration for and production of oil and natural gas;
•difficulties encountered during the exploration for and production of oil and natural gas;
•the potential impact of future drilling on production from existing wells;
•difficulties encountered in delivering oil and natural gas to commercial markets;
•changes in customer demand and producers’ supply;
•the uncertainty of our ability to attract capital and obtain financing on favorable terms;
•compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
•the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
•any increase in severance or similar taxes;
•the financial impact of accounting regulations and critical accounting policies;
•the comparative cost of alternative fuels;
•credit risk relating to the risk of loss as a result of non-performance by our counterparties;
•cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry;
•weather conditions;
•our ability to maintain compliance with the NYSE continued listing requirements and avert delisting of our common stock;
•risks associated with acquisitions, including the Carrizo Acquisition;
•failure to realize the expected benefits of the Carrizo Acquisition;
•any litigation relating to the Carrizo Acquisition; and
•any other factors listed in the reports we have filed and may file with the SEC.
We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our 2019 Annual Report and all quarterly reports on Form 10-Q filed subsequently thereto.
Should one or more of these risks or uncertainties described above or in our 2019 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.
In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.
Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.