Summary of Significant Accounting Policies Significant Accounting Policies (Policies)	12 Months Ended
Dec. 31, 2019
Goodwill [Line Items]
Cash and Cash Equivalents, Policy [Policy Text Block]	We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.
Derivative Financial Instruments, Policy [Policy Text Block]	We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]	We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded
Property, Plant and Equipment, Policy [Policy Text Block]	Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized.
Proved and Unproved Property, Impairment [Policy Text Block]	Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.
Property, Plant and Equipment, Estimated Useful Lives [Policy Text Block]	Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.
Internal Use Software, Policy [Policy Text Block]	Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018, our capitalized costs for internal-use software were $25.9 million and $1.4 million, respectively.
Interest Capitalization, Policy [Policy Text Block]	Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million, $9.2 million and $5.0 million in 2019, 2018 and 2017, respectively.
Assets Held For Sale, Policy [Policy Text Block]	Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.
Income Tax, Policy [Policy Text Block]	We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable.
Debt Issuance Costs, Policy [Policy Text Block]	Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets.
Asset Retirement Obligation [Policy Text Block]	We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.
Treasury Shares, Policy [Policy Text Block]	We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.
Revenue [Policy Text Block]	Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019, 2018 and 2017, the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers.
Accounting for Acquisitions using Purchase Accounting [Policy Text Block]	We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Stock-Based Compensation, Policy [Policy Text Block]	Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.
Earnings Per Share, Policy [Policy Text Block]	Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
Consolidation, Policy [Policy Text Block]	All material intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates, Policy [Policy Text Block]	The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets
Asset Exchange [Policy Text Block]	From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.
New Accounting Pronouncement, Early Adoption [Table Text Block]	In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million, other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.
Goodwill Disclosure [Text Block]	GOODWILL Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $75.1 million. In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in 2017.
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. Restricted Cash. At December 31, 2018, our total cash, cash equivalents and restricted cash of $9.4 million was comprised of $1.4 million of cash and cash equivalents and $8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018. We did not have any restricted cash at December 31, 2019. Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. Properties and Equipment. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018, our capitalized costs for internal-use software were $25.9 million and $1.4 million, respectively. Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million, $9.2 million and $5.0 million in 2019, 2018 and 2017, respectively. Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019, 2018 and 2017, the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement. Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. Recently Adopted Accounting Standards. In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million, other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.

Summary of Significant Accounting Policies Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Cash and Cash Equivalents, Policy [Policy Text Block]

We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Derivative Financial Instruments, Policy [Policy Text Block]

We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes.

Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.

The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]

We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A.

Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded

Property, Plant and Equipment, Policy [Policy Text Block]

Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively.

We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.

Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized.

Proved and Unproved Property, Impairment [Policy Text Block]

Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

Property, Plant and Equipment, Estimated Useful Lives [Policy Text Block]

Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively.

Internal Use Software, Policy [Policy Text Block]

Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018, our capitalized costs for internal-use software were $25.9 million and $1.4 million, respectively.

Interest Capitalization, Policy [Policy Text Block]

Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million, $9.2 million and $5.0 million in 2019, 2018 and 2017, respectively.

Assets Held For Sale, Policy [Policy Text Block]

Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.

Income Tax, Policy [Policy Text Block]

We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable.

Debt Issuance Costs, Policy [Policy Text Block]

Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets.

Asset Retirement Obligation [Policy Text Block]

We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.

Treasury Shares, Policy [Policy Text Block]

We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue [Policy Text Block]

Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019, 2018 and 2017, the impact of any natural gas imbalances was not significant.

Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid.

We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.

Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]

Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers.

Accounting for Acquisitions using Purchase Accounting [Policy Text Block]

We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by

additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.

If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Stock-Based Compensation, Policy [Policy Text Block]

Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.

Earnings Per Share, Policy [Policy Text Block]

Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

Consolidation, Policy [Policy Text Block]

All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates, Policy [Policy Text Block]

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets

Asset Exchange [Policy Text Block]

From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.

New Accounting Pronouncement, Early Adoption [Table Text Block]

In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million, other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.

Goodwill Disclosure [Text Block]

GOODWILL

Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $75.1 million. In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in 2017.

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Restricted Cash. At December 31, 2018, our total cash, cash equivalents and restricted cash of $9.4 million was comprised of $1.4 million of cash and cash equivalents and $8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018. We did not have any restricted cash at December 31, 2019.

Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes.

Properties and Equipment.

Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A.

Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.

Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively.

Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018, our capitalized costs for internal-use software were $25.9 million and $1.4 million, respectively.

Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million, $9.2 million and $5.0 million in 2019, 2018 and 2017, respectively.

Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.

Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable.

Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets.

Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value,

is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.

Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019, 2018 and 2017, the impact of any natural gas imbalances was not significant.

Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers.

Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.

Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.

Recently Adopted Accounting Standards.