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Summary of Significant Accounting Policies (Policies) | 12 Months Ended
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Dec. 31, 2020
Accounting Policies [Abstract] |
Basis of Presentation [Policy Text Block] | Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2020, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements.
Use of Estimates in the Preparation of the Financial Statements [Policy Text Block] | Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents [Policy Text Block] | Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Accounts Receivable [Policy Text Block] | Accounts Receivable The Company’s accounts receivable primarily consists of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure.
Concentration of Credit Risk and Major Customers [Policy Text Block] | Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented:
| For the Years Ended December 31,
| 2020 |  | 2019 |  | 2018
Major customer #1 (1) | — | % |  | 18 | % |  | 18 | %
Major customer #2 (1) | 20 | % |  | 14 | % |  | 5 | %
Major customer #3 (1) | 24 | % |  | 13 | % |  | 7 | %
Major customer #4 (1) | 6 | % |  | 9 | % |  | 10 | %
Major customer #5 (1) | 15 | % |  | 4 | % |  | — | %
Group #1 of entities under common control (2) | 5 | % |  | 13 | % |  | 18 | %
Group #2 of entities under common control (2) | 7 | % |  | 11 | % |  | 12 | %
____________________________________________ (1)These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets and South Texas assets. (2)In the aggregate, these groups of entities under common control represented purchasers of more than 10% of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10% of the Company’s total oil, gas, and NGL production revenue. The Company generally contracts with the affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy is that each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment.
Oil and Gas Producing Activities [Policy Text Block] | Proved properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
Oil and Gas Properties Costs [Policy Text Block] | Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties. The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess.
Property, Plant and Equipment, Impairment [Policy Text Block] | Proved oil and gas property costs are evaluated for impairment on a pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties. The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.
Exploratory [Policy Text Block] | Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows.
Other Property and Equipment [Policy Text Block] | Other Property and Equipment Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.
Asset Retirement Obligations [Policy Text Block] | Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2020, and 2019.
Derivatives Financial Instruments [Policy Text Block] | Derivative Financial Instruments The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and costless collars, as well as, basis differential and roll differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives, please refer to Note 10 – Derivative Financial Instruments.
Revenue Recognition [Policy Text Block] | Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Stock-based Compensation [Policy Text Block] | Stock-Based Compensation At December 31, 2020, the Company had stock-based employee compensation plans that included RSUs and PSUs issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. These are more fully described in Note 7 – Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur.
Income Taxes [Policy Text Block] | Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. Please refer to Note 4 – Income Taxes for additional discussion.
Earnings Per Share [Policy Text Block] | Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 9 - Earnings Per Share for additional discussion.
Comprehensive Income (Loss) [Policy Text Block] | Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss) (“accompanying statements of comprehensive income (loss)”). The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss).
Fair Value of Financial Instruments [Policy Text Block] | Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s revolving credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $93.0 million balance under its revolving credit facility as of December 31, 2020, compared with a $122.5 million balance as of December 31, 2019. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, are recorded at cost, net of any unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.
Industry Segment and Geographic Information [Policy Text Block] | Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment.
Off-Balance Sheet Arrangements [Policy Text Block] | Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2020 or 2019.
Recently Issued Accounting Standards [Policy Text Block] | Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The Company adopted ASU 2016-13 on January 1, 2020, using the modified retrospective method, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company adopted ASU 2019-12 on January 1, 2020, and there was no material impact on the Company’s accompanying consolidated financial statements or related disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2020, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to Note 5 – Long-Term Debt for discussion of the use of the LIBOR in connection with borrowings under the Credit Agreement. In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company plans to adopt ASU 2020-06 on January 1, 2022, and does not expect a material impact on the Company’s accompanying consolidated financial statements or related disclosures. There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2020, and through the filing of this report.
Pension Benefits [Policy Text Block] | The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income (loss), net of tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31.
Leases [Policy Text Block] | Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases. As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include: •Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The weighted-average discount rate used to determine the operating lease liability at December 31, 2020, and 2019, was 7.0 percent and 6.6 percent, respectively. •Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement.

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