Summary of Significant Accounting Policies (Policies) |
12 Months Ended |
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Dec. 31, 2024 | |
| Accounting Policies [Abstract] | |
| Basis of Presentation |
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include our consolidated accounts and the accounts of our wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform with the current year presentation.
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| Segment Reporting |
Segment Reporting
Operating segments are based on components of the Company that engage in business activity that earn revenues and incur expenses and (a) whose operating results are regularly reviewed by our chief operating decision maker (“CODM”) to make decisions about resource allocation and performance and (b) for which discrete financial information is available. The measure of profit or loss that the CODM uses to assess performance and allocated resources to our reportable segments is Net Income. Our chief executive officer is the CODM and uses Net Income to evaluate income generated by each segment in his determination of allocating resources to each segment. As a result, the Company operates two operating segments which represent our reportable segments: Land and Resource Management and Water Services and Operations. The segments enable the alignment of strategies and objectives of TPL and provide a framework for timely and rational allocation of resources within businesses. See Note 15, “Business Segment Reporting” for further information regarding our segments.
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| Use of Estimates in the Preparation of Financial Statements |
Use of Estimates in the Preparation of Financial Statements
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
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| Revenue Recognition |
Revenue Recognition
Oil and Gas Royalties
Oil and gas royalties are received in connection with royalty interests owned by TPL. Oil and gas royalties are reported net of production taxes and are recognized as revenue when crude oil and natural gas products are removed from the respective mineral reserve locations. Oil and gas royalty payments are generally received one to two months after the crude oil and gas products are removed. An accrual for amounts not received during the month crude oil and natural gas products are removed is included in accounts receivable and accrued receivables, net based on historical trends.
The oil and gas royalties which we receive are dependent upon the market prices for oil and gas, and locational and contractual price differences. The market prices for oil and gas are subject to national and international economic and political conditions and subject to significant price fluctuations.
TPL has analyzed public reports of drilling activities by the oil companies operating where we have an oil and gas royalty interest in an effort to identify unpaid royalties associated with royalty interests we own. Rights to certain oil and gas royalties we believe to be due and payable may be subject to dispute with the oil company involved as a result of disagreements with respect to drilling and related engineering information. Disputed oil and gas royalties are recorded when these contingencies are resolved.
Water Sales
Water sales revenue encompasses the sale and delivery of sourced, produced and treated water to operators and other customers, royalties received related to areas of mutual interest (“AMI”), and royalties received pursuant to legacy agreements with operators. In certain instances, we enter into agreements with third parties to provide various water services, including but not limited to, the purchase, sale or transfer of water within a specific geographic area, also known as an AMI. Our performance obligation is deemed satisfied upon the delivery of water at which point, revenue is recognized. In instances where a third party other than the customer is involved in the sale and/or transport of water, such as a revenue share agreement, brokered water sale transaction or third party acquisition of water, the Company will either be acting as the principal or the agent in the water sales transaction. If the Company is deemed to be acting as a principal, the associated revenues are reported on a gross basis in water sales revenue and the corresponding costs associated with the sale are reported as an operating expense in water service-related expenses in the consolidated income statement. If the Company is deemed to be acting as an agent, principally in brokered water transactions, the associated water sales revenue is reported net of the corresponding costs associated with the sale and included in the water sales revenue line item on the consolidated income statement.
Purchases of water from third parties, transfer costs and treatment expenses associated with water sales are included in water service-related expenses.
Produced Water Royalties
Produced water royalties represent revenue from the transfer and disposal of saltwater from producing oil and gas wells on our land. Revenue is recognized when the water is transported across or injected into our land.
Easements and Other Surface-Related Income
Easement contracts represent contracts which permit companies to install pipelines, electric lines and other equipment on land owned by TPL. When TPL receives a signed contract and payment, we make available the respective parcel of land to the grantee. Easement income is recognized upon the execution of the easement agreement, or in the event of a renewal upon receipt of the renewal payment, as at that point in time, we have satisfied our performance obligation and the customer has right of use.
Leases of our surface acreage include, but are not limited to, facility, roadway and surface leases with a typical lease term of 10 years and generally require fixed annual payments. Lease cancellations are allowed under certain circumstances, but initial lease deposits are generally nonrefundable. The initial lease deposits and annual payments are recorded as unearned revenue upon receipt and amortized over the life of the lease. Advance lease payments are deferred and amortized over the appropriate accounting period.
Other surface-related income includes revenue from permits, material sales, and renewable energy sources. Revenue from permits is recognized upon execution of the contract and receipt of payment. Revenue from material sales is recognized upon the removal of materials by the customer. Revenue from renewable energy sources, such as wind and solar power, generally consist of leases, some of which may include a provision for future royalties once certain circumstances occur. As discussed above, lease payments are recorded as unearned revenue and amortized over the life of the lease. Royalties are recognized based upon actual production.
Land Sales and Exchanges
We consider purchasers of land to be our customers as land management, leasing and sales are normal operating activities for TPL. Revenue is recognized on land sales when the performance obligation to the purchaser (customer) is complete. Revenue from land exchanges is recognized based upon the estimated fair value of the consideration exchanged.
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| Cash, Cash Equivalents and Restricted Cash |
Cash, Cash Equivalents and Restricted Cash
We consider investments in bank deposits, money market funds, and other highly-liquid cash investments, such as U.S. Treasury bills and commercial paper, with original maturities of three months or less to be cash equivalents. Our cash equivalents are considered Level 1 assets in the fair value hierarchy.
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| Receivables |
Receivables
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| Accrual Of Oil And Gas Royalties | Accrual of Oil and Gas RoyaltiesThe Company accrues oil and gas royalties, which are included in accounts receivable and accrued receivables, net. An accrual is necessary due to the time lag between the removal of crude oil and natural gas products from the respective mineral reserve locations and generation of the actual payment by operators. The oil and gas royalty accrual is based upon historical production volumes, estimates of the timing of future payments and recent market prices for oil and gas. |
| Fair Value Measurement |
Fair Value Measurement
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date.
The fair value accounting standards establish a fair value hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are those that market participants would use in pricing the asset or liability based on market data obtained from independent sources. Unobservable inputs reflect our assumptions about the inputs market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The fair value hierarchy is categorized into three levels based on the inputs used in measuring fair value, as follows:
Level 1 – Inputs are based on unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access. Since inputs are based on quoted prices that are readily and regularly available in an active market, Level 1 inputs require the least amount of judgment.
Level 2 – Inputs are based on quoted prices for similar instruments in active markets, or are observable either directly or indirectly. Inputs are obtained from various sources including financial institutions and brokers.
Level 3 – Inputs that are unobservable and significant to the overall fair value measurement. The degree of judgment exercised by us in determining fair value is greatest for fair value measurements categorized in Level 3.
We use the highest level of observable market data if such data is available without undue cost and effort.
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| Business Combination and Assets Acquisitions |
Business Combinations and Asset Acquisitions
Our acquisition activities generally include acquisitions of royalty interests and/or land (real estate), and at times, may also include acquisitions of intangible assets or other tangible assets.
When accounting for acquisition activities, we evaluate whether a transaction meets the definition of a business. We first apply a screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. If the screen test is met, the transaction is accounted for as an asset acquisition. If the screen test is not met, we further consider whether the set of assets acquired have, at a minimum, inputs and processes that have the ability to create outputs in the form of revenue. If the assets acquired meet this criteria, the transaction is accounted for as a business combination.
Acquisitions that qualify as an asset acquisition are accounted for using a cost accumulation model whereby the purchase price of the acquisition is allocated to the assets acquired on a relative fair value basis on the date of acquisition. Inputs used to determine such fair values are primarily based upon internally developed models, publicly-available drilling information, a risk-adjusted discount rate and/or publicly-available data regarding transactions consummated by other buyers and sellers, as applicable. These fair values are considered Level 2 and Level 3 assets in the fair value hierarchy. Any associated acquisition costs are capitalized.
Acquisitions that qualify as a business combination are accounted for using the acquisition method of accounting. The fair value of consideration transferred for an acquisition is allocated to the assets acquired and liabilities assumed based on their fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain circumstances. The excess of the consideration transferred over the fair value of assets acquired and liabilities assumed is recorded as goodwill. Conversely, in the event the fair value of assets acquired and liabilities assumed is greater than the consideration transferred, a bargain purchase gain is recognized.
Determining the fair value of assets acquired and liabilities assumed requires judgment and often involves the use of significant estimates and assumptions as fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions involving the acquisition of similar assets and liabilities and the discounted net present value of estimated future cash flows, among others. We engage third-party valuation firms when appropriate to assist in the fair value determination of assets acquired and liabilities assumed. Acquisition-related expenses and transaction costs associated with business combinations are expensed as incurred. We may adjust the amounts recognized in connection with an acquisition during a measurement period not to exceed one year from the date of acquisition, as a result of subsequently obtaining additional information that existed at the acquisition date.
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| Royalty Interests Acquired |
Royalty Interests Acquired
Royalty interests acquired represent royalty interests in proved and unproved oil and gas properties. The cost of acquired oil and gas royalties are capitalized and are accounted for under the successful efforts method. As unproved properties are determined to have proved reserves, the related costs are transferred to proved properties and become subject to depletion at that time.
Estimates of crude oil, natural gas, and NGL reserves affect the calculation of depletion and impairment and also the unaudited standardized measure disclosures associated with our oil and gas royalty interests. We engaged an independent consulting petroleum firm, with assistance from us, to prepare an estimate of proved developed producing reserves, future production and income attributable to our royalty interests as of December 31, 2024. All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of such data. For depletion purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (the “SEC”), the reserve estimates were based on the average prices during the 12-month period prior to December 31, 2024 determined as an unweighted arithmetic average of the first day of the month for each month within the period. Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of our oil and gas royalty interests and/or the rate of depletion related to the oil and gas royalty interests.
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| Depletion of Royalty Interests Acquired |
Depletion of Royalty Interests Acquired
Capitalized costs for proved oil and gas royalty interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions.
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| Real Estate and Royalty Interests Assigned Through the Declaration of Trust |
Real Estate and Royalty Interests Assigned Through the Declaration of Trust
The fair market value of the land and royalty interests that were assigned through the Declaration of Trust (referred to as “Assigned” land and royalty interests) was not determined in 1888 when the Trust was formed; therefore, no value is assigned in the accompanying consolidated balance sheets to the Assigned land and royalty interests. Consequently, in the consolidated statements of income and total comprehensive income, no allowance has been made for depletion and no cost has been deducted from the proceeds of sales of the Assigned land and royalty interests. Even though the 1888 value of real properties cannot be precisely determined, we have concluded that the effect of this matter is no longer significant to our financial position or results of operations. Minimal real estate improvements are made to land
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| Impairment of Long-Lived Assets |
Impairment of Long-Lived Assets
We evaluate long-lived assets, including intangible assets with finite lives and royalty interests acquired with proved oil and gas reserves, for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. When assessing the asset for impairment, we compare the undiscounted future net cash flows to the carrying value to determine recoverability. If the carrying value exceeds the undiscounted future net cash flows, the fair value of the asset is determined and an impairment is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable.
The factors used to determine fair value of proved oil and gas royalty interests include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods. Factors used in the assessment of fair value of unproved oil and gas royalty interests include, but are not limited to, commodity price outlooks and current and future operator activity in the Permian.
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| Amortization of Intangible Assets |
Amortization of Intangible Assets
Intangible assets are amortized on a straight-line basis over their estimated useful lives ranging from 13 to 20 years.
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| Property, Plant and Equipment |
Property, Plant and Equipment
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| Research and Development Activities |
Research and Development Activities
Research and development activities relate to the Company’s initiative to develop an energy-efficient desalination and treatment process for surface discharge and beneficial reuse of produced water. Costs for tangible assets used in these activities that have an alternative future use to the Company are capitalized. All other research and development related expenses are expensed when incurred.
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| Depreciation, Depletion, and Amortization |
Depreciation Expense We account for depreciation of property, plant and equipment on the straight-line method over the estimated useful lives of the assets.
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| Leases |
Leases
We lease certain facilities under operating leases. A determination of whether a contract contains a lease is made at the inception of the arrangement. Our leased facilities include our administrative offices located in Dallas and Midland, Texas.
Our leases generally contain options to extend or terminate the lease. We reevaluate our leases on a regular basis to consider the economic and strategic incentives of exercising the renewal options, and how they align with our operating strategy. Therefore, substantially all of the renewal option periods are not included within the lease term and the associated payments are not included in the measurement of the right-of-use asset and lease liability as the options to extend are not reasonably certain at lease commencement. Short-term leases with an initial term of 12 months or less are not recognized in the right-to-use asset and lease liability on the consolidated balance sheets.
The lease liabilities are measured at the lease commencement date and determined using the present value of the minimum lease payments not yet paid and our incremental borrowing rate, which approximates the rate at which we would borrow, on a collateralized basis, over the term of a lease in the applicable currency environment. The interest rate implicit in the lease is generally not determinable in transactions where we are the lessee.
For real estate leases, we account for lease components and non-lease components (such as common area maintenance) as a single lease component. Certain real estate leases require reimbursement for real estate taxes, common area maintenance and insurance, which are expensed as incurred as variable lease costs. Certain leases contain fixed lease payments for items such as common area maintenance and parking. These fixed payments are considered part of the lease payment and included in the right-of-use assets and lease liabilities. See Note 13, “Commitments and Contingencies” for additional information.
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| Income Taxes |
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination.
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| Share-Based Compensation | Share-Based Compensation The Company utilizes the closing stock price on the date of grant to determine the fair value of stock awards and service-vesting awards, which for the Company includes restricted stock awards (“RSAs”), restricted stock units (“RSUs”), and performance stock units (“PSUs”) with a performance condition. For PSUs with a market condition, grant date fair value is determined using a Monte Carlo simulation model. Unvested awards are entitled to dividends or dividend equivalents which are accrued and distributed to award recipients at the time such awards vest. Dividends are forfeitable if the related award is forfeited. For RSAs, RSUs and PSUs with performance conditions, forfeitures are recognized in the period in which they occur. For PSU awards with market conditions, forfeitures are only recognized if the award recipient does not render the required service during the measurement period.
Share-based compensation expense for restricted stock awards with no requisite service period is recognized in the financial statements immediately on date of grant. Share-based compensation expense for RSUs and RSAs with a requisite service period is recognized in the financial statements over the awards’ vesting periods using the graded-vesting method.
Share-based compensation expense for PSU awards with performance conditions is recognized ratably over the measurement period at such time as the awards are probable and estimable. Share-based compensation expense for PSU awards with market conditions is recognized ratably over the measurement period regardless of whether the market condition is satisfied if the service for the award is rendered. Share-based compensation is reported on the consolidated statements of income and total comprehensive income as a component of salaries and related employee expenses for employee awards and in general and administrative expenses for director awards.
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| Net Income Per Share |
Net Income Per Share
Basic income per share is based on the weighted average number of shares outstanding during the period. Diluted net income per share is computed based upon the weighted average number of shares outstanding during the period plus unvested shares issued pursuant to our equity and deferred compensation plans. See Note 12, “Earnings Per Share.”
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| Treasury Stock |
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the shares of the Company’s common stock, par value $0.01 per share (“Common Stock”), acquired is recorded as treasury stock. The cost associated with issuance of treasury stock is based on the average cost of treasury stock as of the date of issuance.
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| Comprehensive Income (Loss) |
Comprehensive Income (Loss)
Comprehensive income (loss) consists of net income and other gains and losses affecting capital that, under GAAP, are excluded from net income.
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| Concentrations of Credit Risk |
Concentrations of Credit Risk
We invest our cash and cash equivalents (which include U.S. Treasury bills, money market funds, and commercial paper with maturities of three months or less) among three major financial institutions in an attempt to minimize exposure to risk from any one of these entities. As of December 31, 2024 and 2023, we had cash and cash equivalents deposited in our financial institutions in excess of federally-insured levels. We regularly monitor the financial condition of these financial institutions and believe that we are not exposed to any significant credit risk in cash and cash equivalents.
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| Significant Customers |
Significant Customers
Three customers represented, in the aggregate, 40.9% of TPL’s total revenues for the year ended December 31, 2024. Three customers represented, in the aggregate, 42.5% of TPL’s total revenues for the year ended December 31, 2023. Four customers represented, in the aggregate, 51.8% of TPL’s total revenues for the year ended December 31, 2022.
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