DORCHESTER MINERALS, L.P. 10-K

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   2020 Overview   Our results during 2020 were affected by industrywide volatility in terms of COVID-19 pandemic driven demand reductions and price challenges resulting in operator curtailments and decreased activity levels. Significant results include the following:     ● Net income of $21.9 million;     ● Distributions of $48.2 million to our limited partners;     ● Divestiture of our Hugoton net profits interest located in Texas County, Oklahoma and Stevens County, Kansas, to a third party for $5.0 million in proceeds, net of transaction costs and customary holdbacks. This included operated working interests and related properties, our field office and our gathering system and related assets;     ● First payments on 414 gross and three net new wells completed on our Royalty Properties and 90 gross and two net new wells completed on our NPI Properties. The wells were located in 60 counties and parishes in seven states with the majority of the activity concentrated in the Permian Basin and Bakken. Included in these totals are wells in which we own both a royalty interest and a net profits interest. Wells with such overlapping interests are counted in both categories;     ● Total lease bonus of $0.3 million includes consummation of 14 leases and pooling elections of our mineral interest in undeveloped properties located in nine counties in two states.   Critical Accounting Policies   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 units-of-production method. These capitalized costs are subject to a ceiling test that 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.   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. See “Item 8. Financial Statements and Supplementary Data”.   25 Table of Contents   Results of Operations   Normally, our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and average sales prices are shown in the following table.       Years Ended December 31,           Accrual basis sales volumes:   2020     2019     Change %   Royalty Properties natural gas sales (mmcf)     3,484       3,944       (12 )% Royalty Properties oil sales (mbbls)     921       1,055       (13 )% NPI natural gas sales (mmcf)     2,297       2,832       (19 )% NPI oil sales (mbbls)     538       540       - %                           Accrual basis average sales price:                         Royalty Properties natural gas sales ($/mcf)   $ 1.58     $ 1.78       (11 )% Royalty Properties oil sales ($/bbl)   $ 34.24     $ 49.04       (30 )% NPI natural gas sales ($/mcf)   $ 1.33     $ 1.84       (28 )% NPI oil sales ($/bbl)   $ 32.27     $ 46.85       (31 )%   Comparison of the years ended December 31, 2020 and 2019   The decrease in oil sales volumes attributable to our Royalty Properties during 2020 is primarily a result of decreased Permian Basin production due to lower suspense releases on new wells, operator curtailments based on the low commodity price environment, and natural declines, partially offset by higher suspense releases on new wells in the Bakken region and Rockies. The decrease in natural gas sales volumes attributable to our Royalty Properties during 2020 is primarily a result of first and second quarter decreases in production across multiple regions due to operator curtailments based on the low commodity price environment and higher natural declines when compared to the prior year, partially offset by higher suspense releases on new wells in the Bakken, Rockies, and Southeast regions.   Oil sales volumes attributable to our NPI properties remained consistent during 2019 and 2020. The lack of change is primarily a result of higher suspense releases on new wells in the Bakken region and increased production in the Permian Basin, offset by second quarter 2020 Bakken region curtailments due to the low commodity price environment. The decrease in natural gas sales volumes attributable to our NPI properties during 2020 is primarily a result of lower Hugoton Field production contribution due to the September 1, 2020 effective date of the NPI divestiture, declining Fayetteville Shale production, and lower suspense releases on new wells in the Permian Basin compared to 2019, partially offset by increased production in the Permian Basin and Bakken region.   Lease bonus revenue decreased 92% from $3.8 million in 2019 to $0.3 million in 2020. The decrease is primarily a result of higher prior year leasing activity in the Permian Basin when compared to 2020 leasing activity.   Other revenue increased 80% from $0.5 million in 2019 to $0.9 million in 2020. The increase is primarily a result of higher current year favorable normal course of business legal settlements on our Royalty Properties.   Production taxes and operating expenses decreased 14% from $6.6 million in 2019 to $5.7 million in 2020. The decrease is primarily a result of lower production taxes due to lower oil and natural gas sales volumes and lower oil and natural gas prices, partially offset by higher oil and natural gas transportation costs in the Permian Basin and Bakken region.   Depreciation, depletion and amortization decreased 11% from $13.3 million in 2019 to $11.9 million in 2020. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including acquisitions.   General and administrative expenses increased 23% from $6.1 million in 2019 to $7.5 million in 2020. The increase is primarily a result of higher non-recurring land information technology project costs of $0.6 million, higher public company compliance costs, and non-recurring Hugoton and Huffman NPI divestiture transaction and severance costs of $1.0 million, partially offset by lower employee bonus expense.   Net cash provided by operating activities decreased 40% from $66.1 million in 2019 to $39.4 million in 2020. The decrease is primarily a result of lower operating revenues largely driven by lower oil and natural gas sales volumes and realized prices for Royalty properties, lower natural gas sales volumes and oil and natural gas realized prices for NPI properties, and lower lease bonus revenue in 2020 when compared to 2019.   26 Table of Contents   Huffman Acquisition   On March 29, 2019, the Partnership acquired producing and nonproducing mineral, royalty and net profits interests pursuant to a Contribution and Exchange Agreement (the "Contribution and Exchange Agreement") with H. Huffman & Co., A Limited Partnership, an Oklahoma limited partnership (“HHC”), The Buffalo Co., A Limited Partnership, an Oklahoma limited partnership (“TBC” and, together with HHC, the “Acquired Entities”), Huffman Oil Co., L.L.C., an Oklahoma limited liability company, and the equity holders of the Acquired Entities (the “Huffman Acquisition"). The mineral and royalty properties acquired pursuant to the Contribution and Exchange Agreement consisted of varying undivided interests totaling approximately 76,000 net acres located in 169 counties in 14 states, including positions in the Bakken region of North Dakota and interests in multiple enhanced oil recovery units in the Permian Basin. In addition to conveying mineral, royalty and net profits interests to the Partnership, the Acquired Entities delivered funds to the Partnership in an amount equal to their cash receipts during the period from January 1, 2019 through March 29, 2019 of $1.4 million (including adjustments made post-closing). The contributing entities conveyed their interests to the Partnership and affiliates of its General Partner in exchange for 2,400,000 common limited partnership units.   On October 21, 2020, the Partnership and affiliates of its General Partner closed the divestiture of our immaterial HHC entity, including all associated working interest properties and net profits interest.   Net Profits Interest Divestiture   On September 30, 2020, the Partnership and affiliates of its General Partner closed the divestiture of our Hugoton net profits interest located in Texas County, Oklahoma and Stevens County, Kansas to a third party. In accordance with the full cost method of accounting, as the divestiture did not represent a significant portion of the Partnership’s reserves, gross divestiture proceeds of $5.7 million were credited to the oil and natural gas properties full cost pool as of December 31, 2020. Transaction costs of $0.5 million are included in general and administrative expenses on the consolidated income statement for the year ended December 31, 2020. Holdbacks of $0.2 million are included in trade and other receivables on the consolidated balance sheet as of December 31, 2020. Final net proceeds from the sale are subject to customary holdbacks and post-closing adjustments.   Texas Margin Tax   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 such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.   Each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income, franchise and Texas margin tax returns.   Liquidity and Capital Resources   Capital Resources   Our primary sources of capital are our cash flows from the NPI and the Royalty Properties. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from NPIs and the Royalty Properties (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves. Additional cash requirements include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See below for the dates of cash distributions to unitholders.   27 Table of Contents   We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.   Pursuant to the terms of the partnership agreement, we cannot incur indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate at any given time or (ii) which would constitute “acquisition indebtedness” (as defined in Section 514 of the Internal Revenue Code of 1986, as amended).   We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations despite potential material uncertainties that may impact us as a result of the ongoing COVID-19 pandemic and continued oil and natural gas market volatility. Our ability to fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas market and other financial and business factors, including the ongoing COVID-19 pandemic, which are beyond our control. If market conditions were to change due to further declines in oil prices or uncertainty created by the ongoing COVID-19 pandemic, and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced.  We continue to evaluate potential reductions in all discretionary spending. The current economic environment is volatile, and therefore, we cannot predict the ultimate impact on our liquidity or cash flows.   Off-Balance Sheet Arrangements   We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to unitholders.   Liquidity and Working Capital   Cash and cash equivalents were $11.2 million as of December 31, 2020 and $15.3 million as of December 31, 2019.   Distributions   Distributions to limited partners and the General Partner related to cash receipts were as follows:                           In Thousands   Year   Quarter   Record Date   Payment Date   Per Unit Amount     Limited Partners     General Partner   2019   4th   February 3, 2020   February 13, 2020   $ 0.361242     $ 12,528     $ 425   2020   1st   May 4, 2020   May 14, 2020     0.477891       16,573       472   2020   2nd   August 3, 2020   August 13, 2020     0.226318       7,849       202   2020   3rd   November 2, 2020   November 12, 2020     0.325612       11,292       298       Total distributions paid in 2020     $ 48,242     $ 1,397   2020   4th   February 1, 2021   February 11, 2021   $ 0.242260     $ 8,402     $ 279     In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.   Net Profits Interests   We receive monthly payments from the Operating Partnership equal to 96.97% of the net proceeds actually realized by the Operating Partnership from the properties underlying the Net Profits Interest (or “NPI”). The Operating Partnership retains the 3.03% balance of these net proceeds. Net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month, less production costs actually paid during the same month, net of budgeted capital expenditures. Production costs generally reflect drilling, completion, operating and general and administrative costs and exclude depletion, amortization and other non-cash costs. The Operating Partnership made NPI payments to us totaling $19.6 million during October 2019 through September 2020, which payments reflected 96.97% of total net proceeds of $20.2 million realized from September 2019 through August 2020. Net proceeds realized by the Operating Partnership during September through November 2020 were reflected in NPI payments made during October through December 2020. These payments were included in the fourth quarter distribution paid in early 2021 and are excluded from this 2020 analysis.   28 Table of Contents   Royalty Properties   Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs because royalties and lease bonuses generally do not otherwise bear operating or similar costs. After deduction of the above described costs including cash reserves, our net cash receipts from the Royalty Properties during October 2019 through September 2020 were $30.0 million, of which $28.8 million (96%) was distributed to the limited partners and $1.2 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 2020 became part of the fourth quarter distribution paid in early 2021, which is excluded from this 2020 analysis.   Distribution Determinations   The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement. The following calculation covering the period October 2019 through September 2020 demonstrates the method:       In Thousands       Limited Partners     General Partner   4% of net cash receipts from Royalty Properties   $ __     $ 1,201   96% of net cash receipts from Royalty Properties     28,816     __   1% of NPI payments to our Partnership   __       196   99% of NPI payments to our Partnership     19,426     __   Total distributions   $ 48,242     $ 1,397   Operating Partnership share (3.03% of net proceeds)             613   Total General Partner share           $ 2,010   % of total     96 %     4 %   In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our activities and those of the Operating Partnership during this period. Due to these fixed percentages, our General Partner does not have any incentive distribution rights or other right or arrangement that will increase its percentage share of net cash generated by our activities or those of the Operating Partnership.   During the period October 2019 through September 2020, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash. Available cash is defined as all cash and cash equivalents on hand at the end of that quarter (other than cash proceeds received by the Partnership from public or private offering of securities of the Partnership), less any amount of cash reserves that our General Partner determines is necessary or appropriate to provide for the conduct of its business or to comply with applicable laws or agreements or obligations to which we may be subject. Our practice is to accrue funds quarterly for amounts incurred throughout the year but invoiced and paid annually or semi-annually (e.g. ad valorem taxes and professional services). These amounts generally are not held for periods over one year.   Fourth Quarter 2020 Distribution Indicated Price   In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This “indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments.   Cash receipts attributable to the Partnership's Royalty Properties during the 2020 fourth quarter totaled $8.2 million. These receipts generally reflect oil sales during September through November 2020 and natural gas sales during August through October 2020. The average indicated prices for oil and natural gas sales during the 2020 fourth quarter attributable to the Royalty Properties were $35.08/bbl and $1.60/mcf, respectively.   Cash receipts attributable to the Partnership's NPI during the 2020 fourth quarter totaled $1.7 million. These receipts generally reflect oil and natural gas sales from the properties underlying the NPI during August through October 2020. The average indicated prices for oil and natural gas sales during the 2020 fourth quarter attributable to the NPI were $28.52/bbl and $1.39/mcf, respectively.   29 Table of Contents   General and Administrative Costs   In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses subject to certain limitations. We reimburse our General Partner for certain allocable costs, including rent, wages, salaries and employee benefit plans. This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. Through December 31, 2020, the reimbursement amounts actually paid or accrued were less than the limitation.   ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   Not applicable.   ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   The consolidated financial statements are set forth herein commencing on page F-1.   ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   None.