DORCHESTER MINERALS, L.P. 10-K

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   Objective   This discussion, which presents our results of operations for the fiscal years ended December 31, 2021, and December 31, 2020, should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements from period to period, and the primary factors that accounted for those changes.   2021 Overview   Our results during 2021 to a large extent benefitted from industrywide increases in realized oil and natural gas sales prices and increases in Royalty Properties sales volumes from continued drilling activity in the Permian Basin, offset partially by decreases in drilling activity and NPI oil sales volumes in the Bakken and a decrease in NPI natural gas sales due to the divestiture of the Hugoton NPI in 2020. Significant results include the following:     ● Net income of $70.2 million;     ● Distributions of $53.9 million to our limited partners;     ● Acquisition of mineral and royalty interests representing approximately 4,600 net royalty acres located in 27 counties across New Mexico, Oklahoma, Texas and Wyoming in exchange for 1,580,000 common units representing limited partnership interests in the Partnership valued at $31.3 million and issued pursuant to the Partnership's registration statement on Form S-4;     ● Acquisition of overriding royalty interests in the Bakken Trend totaling approximately 6,400 net royalty acres located in Dunn, McKenzie, McLean and Mountrail Counties, North Dakota in exchange for 725,000 common units representing limited partnership interests in the Partnership valued at $12.2 million and issued pursuant to the Partnership's registration statement on Form S-4;     ● First payments on 725 gross and four net new wells completed on our Royalty Properties and 45 gross and less than one net new well completed on our NPI Properties. The wells were located in 51 counties and parishes in eight 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 $0.8 million includes consummation of 16 leases and pooling elections of our mineral interest in undeveloped properties located in eight counties in four states.   22 Table of Contents   Critical Accounting Estimates   The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United State (“U.S. GAAP”), which requires us to make certain estimates and apply judgments that affect our financial position and results of operations as reflected in our financial statements. Actual results may differ from those estimates. The Partnership’s accounting policies are summarized in Note 1 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.   Management continually reviews our accounting policies, how they are applied, and how they are reported and disclosed in our financial statements. The following items require significant estimation or judgment:   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.   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.   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.   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. 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 nonaffiliated entities are particularly subjective due to our inability to gain accurate and timely information. 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.   23 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:   2021     2020     Change %   Royalty Properties natural gas sales (mmcf)     3,665       3,484       5 % Royalty Properties oil sales (mbbls)     1,007       921       9 % NPI natural gas sales (mmcf)     1,344       2,297       (41 )% NPI oil sales (mbbls)     380       538       (29 )%                           Accrual basis average sales price:                         Royalty Properties natural gas sales ($/mcf)   $ 3.63     $ 1.58       130 % Royalty Properties oil sales ($/bbl)   $ 60.26     $ 34.24       76 % NPI natural gas sales ($/mcf)   $ 4.14     $ 1.33       211 % NPI oil sales ($/bbl)   $ 60.68     $ 32.27       88 %   Comparison of the years ended December 31, 2021 and 2020   The increase in oil sales volumes attributable to our Royalty Properties during 2021 is primarily a result of higher suspense releases on new wells in the Permian Basin and Bakken region, partially offset by lower suspense releases on new wells in the Rockies and natural production declines in the Permian Basin, Bakken region, and Mid-Continent. The increase in natural gas sales volumes attributable to our Royalty Properties during 2021 is primarily a result of higher suspense releases on new wells in the Permian Basin and Mid-Continent and increased production in the Bakken region and Barnett Shale, partially largely offset by lower suspense releases on new wells in the Rockies, natural production declines in the Mid-Continent, and decreased production in other areas of Texas and the Southeast region.   The decrease in oil sales volumes attributable to our NPI properties during 2021 is primarily a result of lower suspense releases for new wells in the Bakken region and Permian Basin and natural production declines across all regions. The decrease in natural gas sales volumes attributable to our NPI properties during 2021 is primarily the result of the absence of 2021 production from the Hugoton Field due to the Hugoton NPI divestiture in the third quarter of 2020 and decreased production in Mid-Continent, partially offset by increased production in the Bakken region and increased Fayetteville Shale production due to higher prior period adjustments in the second quarter of 2021.   Production taxes and operating expenses increased 33% from 2020 to 2021. The increase is primarily a result of higher production taxes attributable to higher oil and natural gas sales prices, partially offset by lower ad valorem taxes.   Depreciation, depletion and amortization decreased 12% from 2020 to 2021. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including acquisitions and divestitures.   General and administrative expenses decreased 31% from 2020 to 2021. The decrease is primarily a result of lower compensation expenses due to the forgiveness of the Operating Partnership’s $0.9 million and $0.8 million Paycheck Protection Program loans in the second and third quarter of 2021, respectively, which were applied as non-recurring credits of compensation costs previously reimbursed between the Partnership and the Operating Partnership. The remainder of the decrease is attributable to non-recurring Hugoton and Huffman NPI divestiture transaction and severance costs of $1.0 million in 2020 and lower information technology project costs. These decreases were partially offset by higher compensation expenses due to the reduction of overhead billed to two NPIs which were divested in 2020.   Net cash provided by operating activities increased 78% from 2020 to 2021. The increase is primarily a result of higher Royalties revenue receipts, net of production taxes and operating expenses paid and lower compensation expenses paid due to the forgiveness of the Operating Partnership’s $0.9 million and $0.8 million Paycheck Protection Program loans in the second and third quarter of 2021, respectively, which were applied as non-recurring credits of compensation costs previously reimbursed between the Partnership and the Operating Partnership.   24 Table of Contents   Acquisition for Units   On December 31, 2021, pursuant to a non-taxable contribution and exchange agreement with Gemini 5 Thirty, LP, a Texas limited partnership (“Gemini”), the Partnership acquired mineral and royalty interests representing approximately 4,600 net royalty acres located in 27 counties across New Mexico, Oklahoma, Texas and Wyoming in exchange for 1,580,000 common units representing limited partnership interests in the Partnership valued at $31.3 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complimentary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. At closing, in addition to conveying mineral and royalty interests to the Partnership, Gemini delivered funds to the Partnership in an amount equal to their cash receipts during the period from October 1, 2021 through December 31, 2021 of $1.9 million. The contributed cash, net of capitalized transaction costs paid, of $1.6 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2021.   On June 30, 2021, pursuant to a contribution and exchange agreement with JSFM, LLC, a Wyoming limited liability company (“JSFM”), the Partnership acquired overriding royalty interests in the Bakken Trend totaling approximately 6,400 net royalty acres located in Dunn, McKenzie, McLean and Mountrail Counties, North Dakota in exchange for 725,000 common units representing limited partnership interests in the Partnership valued at $12.2 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complimentary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. At closing, in addition to conveying overriding royalty interests to the Partnership, JSFM delivered funds to the Partnership in an amount equal to their cash receipts during the period from April 1, 2021 through June 30, 2021 of $0.4 million. The contributed cash and final settlement net cash receipts, net of capitalized transaction costs paid, of $0.7 million are included in the net cash contributed in acquisition on the consolidated statement of cash flows for the year ended December 31, 2021.   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.   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, on both a short-term and long-term basis, are our cash flows from the Royalty Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and NPIs (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.   25 Table of Contents   Contractual Obligations   The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The third amendment to our Office Lease was executed in April 2017 for a term of 129 months, beginning June 1, 2018 and expiring in 2029. Under the third amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations are summarized in Note 7 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.   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 spread of COVID-19 and any ongoing variants and continued oil and natural gas market volatility. Although demand and market prices for oil and natural gas have recently increased due to the rising energy demand, we cannot predict events that may lead to future price 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 evolution of COVID-19 and any ongoing variants, which are beyond our control. If market conditions were to change due to declines in oil prices or uncertainty created by COVID-19 or any ongoing variants and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. Despite recent improvements, the current economic environment is volatile, and therefore, we cannot predict the ultimate impact on our liquidity or cash flows.   Liquidity and Working Capital   Cash and cash equivalents were $28.3 million as of December 31, 2021 and $11.2 million as of December 31, 2020.   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   2020   4th   February 1, 2021   February 11, 2021   $ 0.242260     $ 8,402     $ 279   2021   1st   May 3, 2021   May 13, 2021     0.303441       10,523       374   2021   2nd   August 2, 2021   August 12, 2021     0.480528       17,013       602   2021   3rd   November 1, 2021   November 10, 2021     0.507608       17,972       647       Total distributions paid in 2021           $ 53,910     $ 1,902   2022   4th   January 31, 2022   February 10, 2022   $ 0.639287     $ 23,644     $ 855     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 $11.0 million during October 2020 through September 2021, which payments reflected 96.97% of total net proceeds of $11.4 million realized from September 2020 through August 2021. Net proceeds realized by the Operating Partnership during September through November 2021 were reflected in NPI payments made during October through December 2021. These payments were included in the fourth quarter distribution paid February 10, 2022 and are excluded from this 2021 analysis.   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 costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2020 through September 2021 were $44.8 million, of which $43.0 million (96%) was distributed to the limited partners and $1.8 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 2021 became part of the fourth quarter distribution paid in early 2022, which is excluded from this 2021 analysis.   26 Table of Contents   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 2020 through September 2021 demonstrates the method:       In Thousands       Limited Partners     General Partner   4% of net cash receipts from Royalty Properties   $ -     $ 1,792   96% of net cash receipts from Royalty Properties     42,994       -   1% of NPI payments to our Partnership     -       110   99% of NPI payments to our Partnership     10,916       -   Total distributions   $ 53,910     $ 1,902   Operating Partnership share (3.03% of net proceeds)             344   Total General Partner share           $ 2,246   % 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 2020 through September 2021, 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 2021 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 2021 fourth quarter totaled $21.2 million. Approximately 82% of these receipts reflect oil sales during September 2021 through November 2021 and natural gas sales during August 2021 through October 2021, and approximately 18% from prior sales periods. The average indicated prices for oil and natural gas sales during the 2021 fourth quarter attributable to the Royalty Properties were $68.46/bbl and $4.15/mcf, respectively.   Cash receipts attributable to the Partnership's NPI during the 2021 fourth quarter totaled $4.2 million. Approximately 77% of these receipts reflect oil sales and natural gas sales during August 2021 through October 2021, and approximately 23% from prior sales periods. The average indicated prices for oil and natural gas sales during the 2021 fourth quarter attributable to the NPI were $68.11/bbl and $4.20/mcf, respectively.   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, 2021, the reimbursement amounts actually paid or accrued were less than the limitation.   27 Table of Contents   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.