Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Organization and Nature of Business
Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
The Company's operations in the North region comprised 58% of its crude oil and natural gas production and 69% of its crude oil and natural gas revenues for the three months ended March 31, 2020. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. The Company's operations in the South region comprised 42% of its crude oil and natural gas production and 31% of its crude oil and natural gas revenues for the three months ended March 31, 2020. The Company's principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
For the three months ended March 31, 2020, crude oil accounted for 56% of the Company’s total production and 90% of its crude oil and natural gas revenues.
Note 2. Basis of Presentation and Significant Accounting Policies
Basis of presentation
The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q (“Form 10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2019 (“2019 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of March 31, 2020 and for the three month periods ended March 31, 2020 and 2019 are unaudited. The condensed consolidated balance sheet as of December 31, 2019 was derived from the audited balance sheet included in the 2019 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.
Earnings per share
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the three months ended March 31, 2020 and 2019.
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|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
In thousands, except per share data
|
|
2020
|
|
2019
|
Net income (loss) attributable to Continental Resources (numerator)
|
|
$
|
(185,664
|
)
|
|
$
|
186,976
|
|
Weighted average shares (denominator):
|
|
|
|
|
Weighted average shares - basic
|
|
365,403
|
|
|
372,563
|
|
Non-vested restricted stock (1)
|
|
—
|
|
|
1,911
|
|
Weighted average shares - diluted
|
|
365,403
|
|
|
374,474
|
|
Net income (loss) per share attributable to Continental Resources:
|
|
|
|
|
Basic
|
|
$
|
(0.51
|
)
|
|
$
|
0.50
|
|
Diluted
|
|
$
|
(0.51
|
)
|
|
$
|
0.50
|
|
|
|
(1)
|
For the three months ended March 31, 2020 the Company had a net loss and therefore the potential dilutive effect of approximately 594,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.
|
Inventories
Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of March 31, 2020 and December 31, 2019 consisted of the following:
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|
|
|
|
|
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|
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In thousands
|
|
March 31, 2020
|
|
December 31, 2019
|
Tubular goods and equipment
|
|
$
|
15,853
|
|
|
$
|
14,880
|
|
Crude oil
|
|
46,747
|
|
|
94,656
|
|
Total
|
|
$
|
62,600
|
|
|
$
|
109,536
|
|
For the three months ended March 31, 2020, the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at March 31, 2020. The impairment is included in the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive income (loss).
Adoption of new accounting pronouncement
On January 1, 2020 the Company adopted Accounting Standards Update ("ASU") 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. See Note 5. Allowance for Credit Losses for discussion of the adoption impact and the applicable disclosures required by the new standard.
New accounting pronouncement not yet adopted
In December 2019, the Financial Accounting Standards Board ("FASB") issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
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|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
In thousands
|
|
2020
|
|
2019
|
Supplemental cash flow information:
|
|
|
|
|
Cash paid for interest
|
|
$
|
51,111
|
|
|
$
|
61,964
|
|
Cash paid for income taxes
|
|
8
|
|
|
9
|
|
Cash received for income tax refunds (1)
|
|
9,485
|
|
|
4
|
|
Non-cash investing activities:
|
|
|
|
|
Asset retirement obligation additions and revisions, net
|
|
2,508
|
|
|
2,570
|
|
(1) Amount received in the 2020 period primarily represents alternative minimum tax refunds.
As of March 31, 2020 and December 31, 2019, the Company had $232.2 million and $262.7 million, respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets.
As of March 31, 2020 and December 31, 2019, the Company had $1.3 million and $5.6 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" and "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.
As of March 31, 2020 and December 31, 2019, the Company had $1.9 million and $1.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" and "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.
Note 4. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $50.4 million and $41.6 million for the three months ended March 31, 2020 and 2019, respectively.
Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary settlement, but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $10.1 million and $7.5 million for the three months ended March 31, 2020 and 2019, respectively.
Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.
Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
Disaggregation of crude oil and natural gas revenues
The following tables present the disaggregation of the Company's crude oil and natural gas revenues for the three months ended March 31, 2020 and 2019.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2020
|
|
Three months ended March 31, 2019
|
In thousands
|
|
North Region
|
|
South Region
|
|
Total
|
|
North Region
|
|
South Region
|
|
Total
|
Crude oil revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated properties
|
|
$
|
448,930
|
|
|
$
|
179,176
|
|
|
$
|
628,106
|
|
|
$
|
585,605
|
|
|
$
|
136,547
|
|
|
$
|
722,152
|
|
Non-operated properties
|
|
132,939
|
|
|
12,725
|
|
|
145,664
|
|
|
178,728
|
|
|
10,238
|
|
|
188,966
|
|
Total crude oil revenues
|
|
581,869
|
|
|
191,901
|
|
|
773,770
|
|
|
764,333
|
|
|
146,785
|
|
|
911,118
|
|
Natural gas revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated properties
|
|
11,588
|
|
|
72,306
|
|
|
83,894
|
|
|
51,461
|
|
|
124,698
|
|
|
176,159
|
|
Non-operated properties
|
|
1,720
|
|
|
3,359
|
|
|
5,079
|
|
|
10,866
|
|
|
11,441
|
|
|
22,307
|
|
Total natural gas revenues
|
|
13,308
|
|
|
75,665
|
|
|
88,973
|
|
|
62,327
|
|
|
136,139
|
|
|
198,466
|
|
Crude oil and natural gas sales
|
|
$
|
595,177
|
|
|
$
|
267,566
|
|
|
$
|
862,743
|
|
|
$
|
826,660
|
|
|
$
|
282,924
|
|
|
$
|
1,109,584
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timing of revenue recognition
|
|
|
|
|
|
|
|
|
|
|
|
|
Goods transferred at a point in time
|
|
$
|
595,177
|
|
|
$
|
267,566
|
|
|
$
|
862,743
|
|
|
$
|
826,660
|
|
|
$
|
282,924
|
|
|
$
|
1,109,584
|
|
Goods transferred over time
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
$
|
595,177
|
|
|
$
|
267,566
|
|
|
$
|
862,743
|
|
|
$
|
826,660
|
|
|
$
|
282,924
|
|
|
$
|
1,109,584
|
|
Performance obligations
The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
All of the Company's outstanding crude oil sales contracts at March 31, 2020 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.
Contract balances
Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "Receivables–Crude oil and natural gas sales" or "Receivables–Joint interest and other", as applicable, in its condensed consolidated balance sheets.
Revenues from previously satisfied performance obligations
To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the three months ended March 31, 2020 and 2019 related to performance obligations satisfied in prior reporting periods were not material.
Note 5. Allowance for Credit Losses
In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the previously required incurred loss approach with a forward-looking expected credit loss model for accounts receivable and other financial instruments measured at amortized cost. The standard became effective for reporting periods beginning after December 15, 2019. The Company adopted the new standard on January 1, 2020 using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date. The Company's cumulative effect adjustment resulted in a $0.1 million decrease in retained earnings and corresponding decrease in receivables via the recognition of an incremental allowance for credit losses at January 1, 2020.
The Company's principal exposure to credit risk is through the sale of its crude oil and natural gas production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the condensed consolidated balance sheets as "Receivables—Crude oil and natural gas sales” and "Receivables—Joint interest and other.” Presented below are applicable disclosures required by ASU 2016-13 for each portfolio segment.
Historically, the Company's credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $2.7 million and $2.4 million at March 31, 2020 and December 31, 2019, respectively, which is reported as "Allowance for credit losses" in the condensed consolidated balance sheets. Aggregate credit loss expenses totaled $0.7 million and $0.1 million for the three months ended March 31, 2020 and 2019, respectively, which is included in “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss).
Receivables—Crude oil and natural gas sales
The Company's crude oil and natural gas production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil and natural gas sales receivables.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Receivables associated with crude oil and natural gas sales are short term in nature. Receivables from the sale of crude oil and natural gas from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.
The Company’s allowance for credit losses on crude oil and natural gas sales was less than $0.1 million at both March 31, 2020 and December 31, 2019. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three months ended March 31, 2020.
Receivables—Joint interest and other
Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company's credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner's interest.
The Company’s allowance for credit losses on joint interest receivables totaled $2.7 million and $2.4 million at March 31, 2020 and December 31, 2019, respectively. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three months ended March 31, 2020.
Note 6. Derivative Instruments
Natural gas derivatives
As of and for the three months ended March 31, 2019 the Company had outstanding natural gas derivative contracts to economically hedge against the variability in cash flows associated with sales of natural gas production. Such contracts matured in 2019 and the Company had no commodity derivative contracts outstanding at December 31, 2019 and March 31, 2020.
The Company recognizes its derivative instruments, if any, on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value of derivatives is based upon various factors, including commodity exchange prices, over-the-counter quotations and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. Historically, the Company has not designated its derivatives as hedges for accounting purposes and, as a result, marked its derivative instruments to fair value and recognized the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Loss on natural gas derivatives, net”.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Natural gas derivative gains and losses
Cash receipts in the following table reflect the gain on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's 2019 natural gas derivatives were settled based upon reported NYMEX Henry Hub settlement prices. Non-cash losses below represent the change in fair value of derivative instruments which continued to be held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
In thousands
|
|
2020
|
|
2019
|
Cash received on derivatives:
|
|
|
|
|
Natural gas fixed price swaps
|
|
$
|
—
|
|
|
$
|
7,645
|
|
Natural gas collars
|
|
—
|
|
|
5,417
|
|
Cash received on derivatives, net
|
|
—
|
|
|
13,062
|
|
Non-cash loss on derivatives:
|
|
|
|
|
Natural gas fixed price swaps
|
|
—
|
|
|
(8,704
|
)
|
Natural gas collars
|
|
—
|
|
|
(5,482
|
)
|
Non-cash loss on derivatives, net
|
|
—
|
|
|
(14,186
|
)
|
Loss on natural gas derivatives, net
|
|
$
|
—
|
|
|
$
|
(1,124
|
)
|
Note 7. Fair Value Measurements
The Company follows 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 that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
|
|
|
•
|
Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
|
|
|
•
|
Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
|
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's derivative instruments, if any, are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The Company had no outstanding commodity derivative instruments at March 31, 2020 and December 31, 2019.
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At March 31, 2020, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2024 and were then escalated at 3% per year thereafter.
Unobservable inputs to the Company's fair value assessments are reviewed and revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
For the three months ended March 31, 2020, given the significant declines in commodity prices during the quarter the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows and therefore were impaired. Such impairments totaled $181.0 million which reflect fair value adjustments on legacy properties in the Red River Units ($166.5 million) and various non-core properties in the North and South regions ($14.5 million). The impaired properties were written down to their estimated fair value of $145.6 million. Impairments for 2020 also include a $24.5 million impairment to reduce the Company's crude oil inventory to estimated net realizable value at March 31, 2020.
For the three months ended March 31, 2019, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for that period.
Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, 2020 and 2019, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
In thousands
|
|
2020
|
|
2019
|
Proved property impairments
|
|
$
|
205,545
|
|
|
$
|
—
|
|
Unproved property impairments
|
|
16,984
|
|
|
25,316
|
|
Total
|
|
$
|
222,529
|
|
|
$
|
25,316
|
|
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Financial Instruments Not Recorded at Fair Value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2020
|
|
December 31, 2019
|
In thousands
|
|
Carrying
Amount
|
|
Estimated Fair Value
|
|
Carrying
Amount
|
|
Estimated Fair Value
|
Debt:
|
|
|
Credit facility
|
|
$
|
735,000
|
|
|
$
|
735,000
|
|
|
$
|
55,000
|
|
|
$
|
55,000
|
|
Note payable
|
|
4,753
|
|
|
4,800
|
|
|
5,351
|
|
|
5,400
|
|
5% Senior Notes due 2022
|
|
1,099,234
|
|
|
692,400
|
|
|
1,099,165
|
|
|
1,108,700
|
|
4.5% Senior Notes due 2023
|
|
1,458,753
|
|
|
812,200
|
|
|
1,491,339
|
|
|
1,571,400
|
|
3.8% Senior Notes due 2024
|
|
987,644
|
|
|
507,700
|
|
|
994,310
|
|
|
1,034,200
|
|
4.375% Senior Notes due 2028
|
|
989,928
|
|
|
463,700
|
|
|
989,661
|
|
|
1,063,700
|
|
4.9% Senior Notes due 2044
|
|
691,732
|
|
|
298,600
|
|
|
691,688
|
|
|
742,000
|
|
Total debt
|
|
$
|
5,967,044
|
|
|
$
|
3,514,400
|
|
|
$
|
5,326,514
|
|
|
$
|
5,580,400
|
|
The fair value of credit facility borrowings approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.
The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.
The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
Note 8. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $32.4 million and $33.9 million at March 31, 2020 and December 31, 2019, respectively, consists of the following.
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
March 31, 2020
|
|
December 31, 2019
|
Credit facility
|
|
$
|
735,000
|
|
|
$
|
55,000
|
|
Note payable
|
|
4,753
|
|
|
5,351
|
|
5% Senior Notes due 2022
|
|
1,099,234
|
|
|
1,099,165
|
|
4.5% Senior Notes due 2023
|
|
1,458,753
|
|
|
1,491,339
|
|
3.8% Senior Notes due 2024
|
|
987,644
|
|
|
994,310
|
|
4.375% Senior Notes due 2028
|
|
989,928
|
|
|
989,661
|
|
4.9% Senior Notes due 2044
|
|
691,732
|
|
|
691,688
|
|
Total debt
|
|
$
|
5,967,044
|
|
|
$
|
5,326,514
|
|
Less: Current portion of long-term debt
|
|
2,455
|
|
|
2,435
|
|
Long-term debt, net of current portion
|
|
$
|
5,964,589
|
|
|
$
|
5,324,079
|
|
Credit Facility
The Company has an unsecured credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion. The Company had $735 million of outstanding borrowings on its credit facility at March 31, 2020. In March 2020, the Company elected to draw $500 million on its credit facility to increase its cash on hand. At March 31, 2020, the Company's cash on hand totaled $517.6 million.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at March 31, 2020 was 2.6%.
The Company had approximately $762 million of borrowing availability on its credit facility at March 31, 2020 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.25% per annum on the daily average amount of unused borrowing availability.
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at March 31, 2020.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at March 31, 2020. In March 2020 the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions as further discussed below under the heading Repurchase of Senior Notes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2022 Notes (1)
|
|
2023 Notes
|
|
2024 Notes
|
|
2028 Notes
|
|
2044 Notes
|
Face value (in thousands)
|
|
$1,100,000
|
|
$1,466,625
|
|
$993,000
|
|
$1,000,000
|
|
$700,000
|
Maturity date
|
|
Sep 15, 2022
|
|
April 15, 2023
|
|
June 1, 2024
|
|
January 15, 2028
|
|
June 1, 2044
|
Interest payment dates
|
|
March 15, Sep 15
|
|
April 15, Oct 15
|
|
June 1, Dec 1
|
|
Jan 15, July 15
|
|
June 1, Dec 1
|
Make-whole redemption period (2)
|
|
—
|
|
Jan 15, 2023
|
|
Mar 1, 2024
|
|
Oct 15, 2027
|
|
Dec 1, 2043
|
|
|
(1)
|
The Company has the option to redeem all or a portion of its remaining 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
|
|
|
(2)
|
At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
|
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at March 31, 2020.
Three of the Company’s wholly-owned subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, the value of whose assets, equity, and results of operations are not material, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.
Repurchase of Senior Notes
In March 2020, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $33.4 million face value of its 2023 Notes at an aggregate cost of $19.5 million and $7.0 million face value of its 2024 Notes at an aggregate cost of $3.8 million, in each case, including accrued and unpaid interest to the repurchase dates. The repurchased notes were subsequently canceled by the Company. The Company recognized pre-tax gains on extinguishment of debt related to the March 2020 repurchases totaling $17.6 million, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the notes. The gains are reflected in the caption “Gain on extinguishment of debt” in the unaudited condensed consolidated statements of comprehensive income (loss).
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Subsequent to March 31, 2020, the Company repurchased and canceled additional amounts of its 2023 Notes and 2024 Notes. See Note 14. Subsequent Events for further information.
Note payable
In February 2012, 20 Broadway Associates LLC, a wholly-owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.5 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, 2020.
Note 9. Leases
The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $12.6 million as of March 31, 2020 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company's leasing activities as a lessor are negligible.
|
|
|
|
|
|
In thousands
|
|
Amount
|
Drilling rig commitments
|
|
$
|
6,048
|
|
Surface use agreements
|
|
5,091
|
|
Field equipment
|
|
1,105
|
|
Other
|
|
339
|
|
Total
|
|
$
|
12,583
|
|
Drilling rig commitments reflected above represent minimum payment obligations expected to be incurred on enforceable commitments with durations in excess of one year at the inception of the lease.
Minimum future commitments by year for the Company's operating leases as of March 31, 2020 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.
|
|
|
|
|
|
In thousands
|
|
Amount
|
Remainder of 2020
|
|
$
|
4,954
|
|
2021
|
|
2,574
|
|
2022
|
|
782
|
|
2023
|
|
729
|
|
2024
|
|
456
|
|
Thereafter
|
|
6,676
|
|
Total operating lease liabilities, at undiscounted value
|
|
$
|
16,171
|
|
Less: Imputed interest
|
|
(3,588
|
)
|
Total operating lease liabilities, at discounted present value
|
|
$
|
12,583
|
|
Less: Current portion of operating lease liabilities
|
|
(6,243
|
)
|
Operating lease liabilities, net of current portion
|
|
$
|
6,340
|
|
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals.
|
|
|
|
|
|
In thousands, except weighted average data
|
|
Three months ended March 31, 2020
|
Lease costs:
|
|
|
Operating lease costs
|
|
$
|
1,260
|
|
Variable lease costs
|
|
3,223
|
|
Short-term lease costs
|
|
51,348
|
|
Total lease costs
|
|
$
|
55,831
|
|
|
|
|
Other information:
|
|
|
Right-of-use assets obtained in exchange for new operating lease liabilities
|
|
$
|
7,002
|
|
Operating cash flows from operating leases included in lease liabilities
|
|
228
|
|
Weighted average remaining lease term as of March 31, 2020 (in years)
|
|
9.8
|
|
Weighted average discount rate as of March 31, 2020
|
|
4.1
|
%
|
Note 10. Commitments and Contingencies
Included below is a discussion of certain future commitments and contingencies of the Company as of March 31, 2020.
Drilling rig commitments – As of March 31, 2020, the Company has drilling rig contracts with various terms extending to April 2021. Future operating day-rate commitments as of March 31, 2020 total approximately $36 million, of which $33 million is expected to be incurred in the remainder of 2020 and $3 million will be incurred in 2021. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations with a discounted present value totaling $6.0 million that are required to be recognized on the Company's balance sheet at March 31, 2020 in accordance with ASC Topic 842 as discussed in Note 9. Leases.
Other lease commitments – The Company has various other lease commitments primarily associated with surface use agreements and field equipment. See Note 9. Leases for additional information.
Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of March 31, 2020 under the arrangements amount to approximately $2.11 billion, of which $210 million is expected to be incurred in the remainder of 2020, $326 million in 2021, $329 million in 2022, $331 million in 2023, $298 million in 2024, and $615 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company's balance sheet.
Litigation – The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. As of March 31, 2020 and December 31, 2019, the Company had recognized a liability within “Other noncurrent liabilities” of $7.5 million and $8.7 million, respectively, for various matters, none of which are believed to be individually significant. See Note 14. Subsequent Events for discussion of a new legal matter involving the Company that was initiated subsequent to March 31, 2020.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 11. Stock-Based Compensation
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan, as amended ("2013 Plan"). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss), was $16.4 million and $12.1 million for the three months ended March 31, 2020 and 2019, respectively.
In March 2019, the Company amended and restated its 2013 Plan and reserved 12,983,543 shares of common stock that may be issued pursuant to the amended plan. The 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited after issuance. As of March 31, 2020, the Company had 10,871,733 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends if any, subject to forfeiture. Restricted stock grants generally vest over periods ranging from 1 to 3 years.
A summary of changes in non-vested restricted shares outstanding for the three months ended March 31, 2020 is presented below.
|
|
|
|
|
|
|
|
|
|
|
Number of
non-vested
shares
|
|
Weighted average
grant-date
fair value
|
Non-vested restricted shares outstanding at December 31, 2019
|
|
3,461,908
|
|
|
$
|
46.82
|
|
Granted
|
|
2,454,235
|
|
|
28.41
|
|
Vested
|
|
(925,568
|
)
|
|
46.19
|
|
Forfeited
|
|
(42,818
|
)
|
|
39.88
|
|
Non-vested restricted shares outstanding at March 31, 2020
|
|
4,947,757
|
|
|
$
|
37.87
|
|
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the three months ended March 31, 2020 was approximately $24 million. As of March 31, 2020, there was approximately $117 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.9 years.
Note 12. Shareholders' Equity
Share repurchases
For the three months ended March 31, 2020, the Company repurchased and retired approximately 8.1 million shares of its common stock at an aggregate cost of $126.9 million. Through March 31, 2020, the Company had repurchased and retired a cumulative total of approximately 13.8 million shares at an aggregate cost of $317.1 million since the inception of its $1 billion share repurchase program in June 2019.
The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time.
Dividend payment
On January 27, 2020 the Company declared a quarterly cash dividend of $0.05 per share on its outstanding common stock, which amounted to $18.4 million and was paid on February 21, 2020 to shareholders of record as of February 7, 2020.
To preserve cash in response to the significant reduction in crude oil prices and economic turmoil resulting from the COVID-19 pandemic, in April 2020 the Company’s quarterly dividend was suspended by the Board of Directors until further notice.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 13. Income Taxes
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.
The Company's provision (benefit) for income taxes and resulting effective tax rates were as follows for the periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
|
2020
|
|
2019
|
Provision (benefit) for income taxes (in thousands)
|
|
$
|
(52,235
|
)
|
|
$
|
51,990
|
|
Effective tax rate
|
|
21.9
|
%
|
|
21.8
|
%
|
The Company computes its quarterly income tax provision (benefit) under the effective tax rate method based on applying an anticipated annual effective tax rate to year-to-date pre-tax income (loss), except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.
The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity compensation, valuation allowances, and other tax items as reflected in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
In thousands, except tax rates
|
|
2020
|
|
2019
|
Income (loss) before income taxes
|
|
$
|
(239,019
|
)
|
|
$
|
238,483
|
|
U.S. federal statutory tax rate
|
|
21.0
|
%
|
|
21.0
|
%
|
Expected income tax provision (benefit) based on U.S. federal statutory tax rate
|
|
(50,194
|
)
|
|
50,081
|
|
Items impacting the effective tax rate:
|
|
|
|
|
State and local income taxes, net of federal benefit
|
|
(7,603
|
)
|
|
7,798
|
|
Equity compensation
|
|
3,886
|
|
|
(8,318
|
)
|
Other, net
|
|
(3,189
|
)
|
|
2,429
|
|
Valuation allowance
|
|
4,865
|
|
|
—
|
|
Provision (benefit) for income taxes
|
|
$
|
(52,235
|
)
|
|
$
|
51,990
|
|
Effective tax rate
|
|
21.9
|
%
|
|
21.8
|
%
|
The Company reduces its deferred tax assets by a valuation allowance if, based upon the weight of available evidence, it is more-likely-than-not that the Company will not realize some portion or all of the deferred tax assets. The Company considers relevant evidence, both positive and negative, to determine the need for a valuation allowance. Information evaluated includes the Company's financial position and results of operations for the current and preceding years, the availability of deferred tax liabilities and tax carrybacks, as well as an evaluation of currently available information about future years. The Company determined it was more-likely-than-not that a portion of its Oklahoma NOL carryforwards would not be able to be utilized before expiration, and a valuation allowance of approximately $4.9 million was established for the deferred tax assets associated with such NOL carryforwards.
The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.
Note 14. Subsequent Events
In March 2020, the World Health Organization declared a global pandemic related to the proliferation of COVID-19 (novel coronavirus). The adverse economic effects of the COVID-19 pandemic continue to evolve as of the filing of this report. The catastrophe caused by the COVID-19 pandemic has materially decreased global and domestic demand for crude oil based on changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic. This destruction of
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
demand has led to an unprecedented decline in crude oil prices. In response to these developments, the Company began shutting in production in April 2020 and currently has approximately 70% of its operated crude oil production and associated natural gas shut-in. The duration and extent of our production shut-ins are being evaluated on an ongoing basis and are subject to change as market conditions evolve. Given the uncertain duration of the catastrophe caused by the COVID-19 pandemic and the potential for a longer-term impact on consumer behaviors, the Company is not able to estimate the effects of the pandemic on its results of operations, financial condition, or cash flows for the remainder of 2020. Nevertheless, a near term material negative impact on the Company's production, revenues, cash flows, and earnings is certain to occur for the second quarter of 2020.
On April 15, 2020, Casillas Petroleum Resource Partners II, LLC filed a petition against the Company in the District Court of Tulsa County, State of Oklahoma. In its petition Casillas alleges the Company breached a Purchase and Sale Agreement (“PSA”) to purchase oil and gas interests in Oklahoma for $200 million. Casillas seeks specific performance. The Company terminated the PSA due to Casillas’ breach of the agreement and denies the allegations and will vigorously defend the claims. The Company will also seek affirmative relief. The Company is not currently able to estimate what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations, or cash flows due to the preliminary status of the matter.
In April 2020, the Company repurchased and canceled an additional $17.0 million face value of its 2023 Notes at an aggregate cost of $9.8 million and an additional $82.0 million face value of its 2024 Notes at an aggregate cost of $43.1 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company estimates it will recognize pre-tax gains on extinguishment of debt related to the April 2020 repurchases totaling $47.0 million, which include the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the notes. The reduction in debt and associated extinguishment gains from the April 2020 repurchases will be reflected in the Company's second quarter 2020 results.