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Note 1 - General and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Basis of Presentation and Significant Accounting Policies [Text Block]

1.

General and Summary of Significant Accounting Policies

Nature of Operations — In these Notes, the term “Partnership,” as well as the terms “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities. Our Partnership is a Dallas, Texas based owner of producing and nonproducing natural gas and crude oil royalty, net profits, and leasehold interests in 587 counties and 27 states. We are a publicly traded Delaware limited partnership that was formed in December 2001 and commenced operations on January 31, 2003.

Basis of Presentation — The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

Basic and Diluted Earnings Per Unit — Per-unit information is calculated by dividing the net income applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, accordingly, basic and dilutive net income per unit do not differ.

Principles of Consolidation — The consolidated financial statements include the accounts of Dorchester Minerals, L.P., Dorchester Minerals Oklahoma, LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, Dorchester-Maecenas GP LLC, The Buffalo Co., A Limited Partnership, and DMLPTBC GP LLC. All intercompany balances and transactions have been eliminated in consolidation.

Estimates — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. For example, estimates of uncollected revenues and unpaid expenses from Royalty Properties (which are interests in oil and natural gas leases that give the Partnership the right to receive a portion of the production from the leased acreage, without bearing the costs of such production) and net profits overriding royalty interests (referred to as the Net Profits Interest, or “NPI”) operated by non-affiliated entities are particularly subjective due to our inability to gain accurate and timely information. Therefore, actual results could differ from those estimates.

The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. See the discussion under Oil and Natural Gas Properties.

General Partner—Our general partner is Dorchester Minerals Management LP, referred to in these Notes as “our General Partner.” Our General Partner owns all of the partnership interests in Dorchester Minerals Operating LP, the Operating Partnership. See Note 4 —Related Party Transactions. The General Partner is allocated 4% and 1% of our Royalty Properties’ net revenues and Net Profits Interest proceeds received by the Operating Partnership, respectively.

Cash and Cash Equivalents—Our principal banking relationships are with major financial institutions. Cash balances in these accounts may, at times, exceed federally insured limits. We have not experienced any losses in such cash accounts and do not believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with an original maturity of three months or less are considered to be cash equivalents and are carried at cost, which approximates fair value.

Concentration of Credit Risks and Significant Customers—Our Partnership, as a royalty and NPI owner, has extremely limited involvement and no control over the volumes or method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI. If we were to lose a significant customer, such loss could impact revenue. The loss of any single customer is mitigated by our diversified customer base, and we do not believe that the loss of any single customer would have a long-term material adverse effect on our financial position or the results of operations.

Fair Value of Financial Instruments—The carrying amount of cash and cash equivalents, trade and other receivables, and accounts payables and other current liabilities approximates fair value because of the short maturity of those instruments. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized as of year-end or that will be realized in the future.

Receivables—Our Partnership’s trade and other receivables and net profits interests receivable consist primarily of Royalty Properties payments receivable and NPI payments receivable, respectively. Most payments are received two to four months after production date. No allowance for doubtful accounts is deemed necessary based upon our lack of historical write offs and review of current receivables.

Oil and Natural Gas Properties — We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. These capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. Our Partnership did not assign any value to unproved properties as of December 31, 2020, including nonproducing royalty, mineral, and leasehold interests. The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. There have been no impairments for the years ended December 31, 2020 and 2019.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.

Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion (greater than 25%) of our Partnership’s reserves. Proceeds from other dispositions of oil and natural gas properties are credited to the full cost pool.

Leasehold Improvements — Leasehold improvements are amortized over the shorter of their estimated useful lives or the related life of the lease.

Leases — The Partnership determines if an arrangement is a lease at inception. The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The operating lease is included in operating lease right-of-use (“ROU”) asset and operating lease liability in our consolidated balance sheets. Operating lease expense is included in general and administrative expenses in the consolidated income statements.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. As the Partnership’s lease does not provide an implicit rate of return and as the Partnership is precluded from incurring any borrowings above a nominal amount under its partnership agreement, the Partnership used a discount rate commensurate with the incremental borrowing rate of a group of peers based on information available at the application date in determining the present value of lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

Asset Retirement Obligations — Based on the nature of our property ownership, we have no material obligations to record.

Revenue Recognition — The pricing of oil and natural gas sales from the Royalty Properties and NPI is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have extremely limited involvement and no operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI.

Revenues from Royalty Properties and NPI are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices. Identified differences between our accrued revenue estimates and actual revenue received historically have not been significant.

The Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations. The Partnership’s right to revenues from Royalty Properties and NPI occurs at the time of production, at which point, payment is unconditional, and no remaining performance obligation exists for the Partnership. Accordingly, the Partnership’s revenue contracts for Royalty Properties and NPI do not generate contract assets or liabilities.

Revenues from lease bonus payments are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Partnership upon receipt of payment. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies and includes proceeds from assignments of leasehold interests where the Partnership retains an interest. A lease agreement represents the Partnership’s contract with a lessee and generally transfers the rights to develop oil or natural gas, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Upon signing a lease agreement, no further performance obligation exists for the Partnership, and therefore, no contract assets or contract liabilities are generated.

Income Taxes — We are treated as a partnership for income tax purposes and, as a result, our income or loss is includable in the tax returns of the individual unitholders. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements will not be indicative of the depletion expense an individual partner or unitholder may be able to deduct for income tax purposes.

Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, joint ventures, and certain other business entities having limited liability protection.

Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code provides that such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.

Recent Events – In January 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (“COVID-19”) and the significant risks to the international community and economies as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified COVID-19 as a pandemic, based on the rapid increase in exposure globally, and throughout the second, third, and fourth quarters of 2020 and thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In addition, after the Organization of the Petroleum Exporting Countries (“OPEC”) and a group of oil producing nations led by Russia failed in March 2020 to agree on oil production cuts, Saudi Arabia announced that it would cut oil prices and increase production, leading to a sharp further decline in oil and natural gas prices. While OPEC, Russia and other oil producing countries reached an agreement in April 2020 to reduce production levels, and U.S. production has declined, a significant crude oil price recovery is not expected until global supply matches current lower levels of demand caused by a number of factors, including the uncertainty around the extent and timing of an economic recovery due to the continued COVID-19 pandemic. The effects of COVID-19 and concerns regarding its domestic and global spread, as well as the actions by Russia and Saudi Arabia in the first and second quarters of 2020, could continue to negatively impact the domestic and international supply and demand for oil and natural gas, to sustain continued price volatility and impact the price paid for oil and natural gas and to materially and adversely affect the demand for and marketability of oil and natural gas production.

We are closely monitoring the current and potential impact of the COVID-19 pandemic and future OPEC actions on all aspects of our business, including how these events may impact our future operations, financial results, liquidity, employees and operators. The impact of the COVID-19 pandemic and the related economic downturn and the historically low oil and natural gas prices on the account of the oil price war between OPEC and other oil producing countries is rapidly evolving. We cannot predict the long-term impact of these events on our liquidity, financial position, results of operations or cash flows due to uncertainties including the severity of COVID-19, the duration of the outbreak domestically and worldwide, additional governmental or other actions taken to combat COVID-19 and the effect COVID-19 and the current depressed oil prices will have on the demand for oil and natural gas. These situations remain fluid and unpredictable, and we are actively managing our response.