Distributions beginning with the second quarter of 2017 were paid on 32,279,774 units; previous distributions set forth above were paid on 30,675,431 units. The third quarter 2017 distribution2022 will be paid on November 9, 2017. Fourth37,554,774 common units. The second quarter distributions shown above are2022 distribution of $0.969012 per common unit will be paid inon August 11, 2022. The distribution for the first calendarsecond quarter of the following year.2021 was paid on 35,404,774 common units. Our partnership agreement requires the fourththird quarter cash distribution to be paid by FebruaryNovember 14, 2018.

5       New Accounting Pronouncements: In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The guidance requires entities to recognize revenue using the following five-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation. Adoption of this standard could result in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. The company plans to adopt this standard using the modified retrospective method upon its effective date. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017.

 Our Partnership’s revenues are substantially attributable to oil and gas sales. Based on substantial completion of review of our contracts, we believe the timing and presentation of revenues under ASU 2014-09 will be materially consistent with our current revenue recognition policy as described above. The Partnership will continue to monitor specific developments for our industry as it relates to ASU 2014-09.2022.

The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this Quarterly Report on Form 10-Q.

Objective

This discussion, which presents our results of operations for the three and six months ended June 30, 2022 and June 30, 2021, should be read in conjunction with our Condensed 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.

Overview

We own producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty Properties. We currently own Royalty Properties in 574590 counties and parishes in 2528 states.

 WeAs of June 30, 2022, we own a net profits overriding royalty interestsinterest (referred to as the Net Profits Interests,Interest, or “NPIs”“NPI”) in various properties owned by Dorchester Minerals Operating LP (the “Operating Partnership”), a Delaware limited partnership owned directly and indirectly by our general partner. We refer to Dorchester Minerals Operating LP as the “operating partnership” or “DMOLP.”General Partner. We receive monthly payments from the NPI equaling 96.97% of the net profits actually realized by the operating partnershipOperating Partnership from these properties in the preceding month. In the event that costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for properties subject to athe Net Profits Interest, no payment is made, and any deficit is accumulated and carried over and reflected in the following month's calculation of net profit.

 Each of the five NPIs have previously had cumulative revenue that exceeded cumulative costs, such excess constituting net proceeds on which NPI payments were determined. In the event anthe NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the operating partnership.Operating Partnership.

 Minerals NPI production volumes and prices are withinFrom a cash perspective, as of June 30, 2022, the consolidated financial statements in accordance with U.S. GAAP. Our financial statements will continue to reflect such information even if the NPI is in temporary deficit due to capital expenditures.

 As of September 30, 2017, the Minerals NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, equaling cash on hand of $7,400,000.$4.1 million.

Commodity Price Risks

The pricing of oil and natural gas sales is primarily determined by supply and demand in the global marketplace and can fluctuate considerably. As a royalty owner and non-operator, we have extremely limited access to timely information and involvement and no operational control over the volumes of oil and natural gas produced and sold or the terms and conditions on which such volumes are marketed and sold.

Our profitability is affected by oil and natural gas market prices. Oil and natural gas market prices have fluctuated significantly in recent years in response to changes in the supply and demand for oil and natural gas in the market, along with domestic and international political and economic conditions.

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 spread 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 thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In addition, in early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the COVID-19 pandemic. Additionally, multiple variants emerged in 2021 and became highly transmissible, which contributed to additional pricing and demand volatility during 2021 to date. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations became available for COVID-19 since late 2020.

Furthermore, in February 2022, Russian military forces invaded Ukraine leading to various trade and economic sanctions being implemented by countries and private market participants on Russia which have resulted in a global supply shortage of oil and natural gas.

As a result of the lifting of certain restrictions put in place in response to COVID-19 and the global supply shortage of oil and natural gas caused by the Russian invasion of Ukraine, in addition to other changing market conditions, oil and natural gas market prices have shown sharp increases. While global economic recovery has recently softened due to higher inflation and rising interest rates, demand and market prices for oil and natural gas remain strong. However, commodity prices have historically been volatile, and we cannot predict events which may lead to future fluctuations in these prices. Additional actions may be required in response to the COVID-19 pandemic on a national, state and local level by governmental authorities, and such actions may further adversely affect general and local economic conditions (including further closures of businesses), particularly if the resurgence and spread of the COVID-19 pandemic continues. The COVID-19 pandemic continues to be dynamic and evolving, and its ultimate duration and effects remain uncertain. Similarly, the length, impact and outcome of the ongoing military conflict between Russia and Ukraine is highly unpredictable and could lead to significant market disruptions and increased volatility in oil and natural gas prices and supply of energy resources along with instability in the global commodity and financial markets.

Results of Operations

ThreeAcquisition for Units

On March 31, 2022, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests representing approximately 3,600 net royalty acres located in 13 counties across Colorado, Louisiana, Ohio, Oklahoma, Pennsylvania, West Virginia and Wyoming in exchange for 570,000 common units representing limited partnership interests in the Partnership valued at $14.8 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complementary 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. Contributed cash delivered at closing and final settlement net cash received during the three months ended June 30, 2022, net of capitalized transaction costs paid, of $0.9 million are included in net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the six months ended June 30, 2022.

On December 31, 2021, pursuant to a non-taxable contribution and exchange agreement with 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 complementary 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. Final settlement net cash received during the six months ended June 30, 2022, net of capitalized transaction costs, of $0.1 million are included in the net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the six months ended June 30, 2022.

On June 30, 2021, pursuant to a non-taxable contribution and exchange agreement with 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 complementary 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. Contributed cash delivered at closing, net of capitalized transaction costs, of $0.4 million is included in the net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the six months ended June 30, 2021.

Three and Nine Six Months Ended September 30, 2017June 30, 2022 as compared to Three and Nine Six Months Ended June 30,2021September30, 2016

Normally, our period-to-periodOur 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.prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and weighted average sales prices were:are shown in the following table. Oil sales volumes include volumes attributable to natural gas liquids and oil sales prices include natural gas liquids prices combined by volumetric proportions.

Both oil and natural gas sales price changes reflected in the table above resulted from changing market conditions.

OilThe increase in oil sales volumes attributable to our Royalty Properties duringfrom the thirdsecond quarter increased 27% from 163 mbbls in 2016of 2021 to 207 mbbls in the same period of 2017. Oil sales volumes attributable to the first nine months of 2016 increased 26% from 451 mbbls to 569 mbbls in the same period of 2017. The increase in volumes during the third quarter and first nine months of 2017 compared to the same periods of 20162022 is mainly a result of increased Permian Basin production from new wells. Natural gas sales volumes attributable to our Royalty Properties during the third quarter increased 25% from 775 mmcf in 2016 to 967 mmcf in the same period of 2017. Natural gas sales volumes during the first nine months increased 9% from 2,461 mmcf in 2016 to 2,681 mmcf in the same period of 2017. The increase in volumes during the third quarter and first nine months of 2017 compared to the same periods of 2016 is mainlyprimarily a result of increased production in the Permian Basin, partially offset by decreased productionRockies, and Bakken region and higher suspense releases on new wells in the Fayetteville Shale play.

OilPermian Basin. The increase in oil sales volumes attributable to our NPIs duringRoyalty Properties from the third quarter and first ninesix months of 2016 were 84 mbbls and 307 mbbls, respectively, resulting in decreases of 29% and 35%2021 to 60 mbbls and 200 mbbls, respectively, during the same periodsperiod of 2017.2022 is primarily a result of increased production in the Permian Basin, Rockies, and Bakken region and higher suspense releases on new wells in the Permian Basin and Rockies. The decreaseincrease in natural gas sales volumes attributable to our Royalty Properties from the second quarter of 2021 to the same period of 2022 is primarily a result of increased production in the Permian Basin, Rockies, Mid-Continent, and East Texas and higher suspense releases on new wells in the Permian Basin, partially offset by natural production declines in the Barnett Shale, Fayetteville Shale, and Bakken region. The increase in natural gas sales volumes attributable to our Royalty Properties from the first six months of 2021 to the same period of 2022 is primarily a result of increased production in the Permian Basin, Rockies, Mid-Continent, and Southeast and higher suspense releases on new wells in the Permian Basin, Rockies, and Southeast, partially offset by natural production declines in the Barnett Shale.

The increase in oil sales volumes attributable to our NPI properties from the second quarter of 2021 to the same period of 2022 is mainlyprimarily a result of increased production in the Permian Basin and higher suspense releases on new wells in the Permian Basin and Bakken region. The increase in oil sales volumes attributable to our NPI properties from the first six months of 2021 to the same period of 2022 is primarily a result of increased production in the Permian Basin and higher suspense releases on new wells in the Permian Basin and Bakken region, partially offset by natural production declines in the Bakken region. The decrease in natural gas sales volumes attributable to our NPI properties from the second quarter of 2021 to the same period of 2022 is primarily a result of a decrease in production in the Permian Basin, natural production declines in the Bakken region, and decreased Fayetteville Shale production due to natural reservoir declines.higher prior period adjustments in the second quarter of 2021, partially offset by higher suspense releases on new wells in the second quarter of 2022. Natural gas sales volumes attributable to our NPIs duringNPI properties remained consistent from the third quarter increased 5% from 599 mmcf in 2016first six months of 2021 to 631 mmcf in the same period of 20172022. This is primarily a result of increased production in the Permian Basin and higher suspense releases on new wells in the Permian Basin, offset by natural production declines in the Bakken region and decreased Fayetteville Shale production due to a higher numberprior period adjustments in the second quarter of suspense releases in 2017. During2021.

Lease bonus revenue increased 182% from the first ninesix months of 2017, NPI natural gas volumes decreased 10% from 1,996 mmcf in 20162021 to 1,799 mmcf in the same period of 2017. The decrease in gas sales volumes2022. This increase and the second quarter of 2022 lease bonus revenue is mainly dueprimarily attributable to natural reservoir declines in addition to the lower amountreceipt of suspense releasesa bonus from a lease consummated in the firstPermian Basin in the second quarter of 2017 as compared to2022.

Operating costs, including production taxes, increased 132% from the firstsecond quarter of 2016.

Our third quarter net operating revenues increased 17% from $10,679,000 during 20162021 to $12,480,000 during the same period of 2017. Current quarter increase in royalty revenues is primarily due2022 and 124% from the first six months of 2021 to higher oil and natural gas prices, partially offset by a decrease in both net profits interests income and lease bonus income versus the prior year. Our first nine months net operating revenues increased 41% from $26,814,000 during 2016 to $37,760,000 during the same period of 2017. These2022. The increases are primarily a result of an increase in royalty revenues resulting from higher oil and natural gas prices and sales volumes.

Third quarter operating costs and expenses increased 46% from $902,000 during 2016 to $1,320,000 during the same period of 2017. Our first nine months operating costs increased 54% from $2,180,000 during 2016 to $3,358,000 during the same period of 2017. The increases in both periods are primarily a result of higherproportionate production taxes due to higher Royalty Properties oil and natural gas sales prices.volumes and higher sales prices and ad valorem taxes.

GeneralDepreciation, depletion and administrative expenses of $1,050,000 duringamortization increased 92% from the thirdsecond quarter of 2016 increased 9% to $1,141,000 during the same period of 2017 primarily as a result of costs related to our office remodel. General and administrative expenses of $3,967,000 during the first nine months of 2016 decreased 5% compared to $3,764,000 during the same period of 2017. The decrease is primarily due to lower information technology costs and lower legal costs associated with royalty litigation partially offset by increased costs related to our office remodel as compared2021 to the same period of 2016.

Depletion2022 and amortization costs93% from the first six months of $2,080,000 during the third quarter of 2016 increased 34%2021 to $2,795,000 during the same period of 2017 due to additional depletion from recently acquired mineral and royalty interests. Depletion and amortization costs of $6,571,000 during the first nine months of 2016 decreased 2% compared to $6,443,000 during the same period of 2017. We2022.We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves.reserves, including recent acquisitions.

ThirdGeneral and administrative expenses increased 115% from the second quarter net income allocableof 2021 to common units increased 8% from $6,417,000 during 2016 to $6,951,000 during the same period of 2017 mainly due2022 and 24% from the first six months of 2021 to higher royalty income. Our first nine months net income allocable to common units increased by 71% from $13,600,000 compared to $23,292,000 during the same period of 2017.2022. The increase is mainlyincreases are primarily a result of higher compensation expenses due to higher royalty income duethe forgiveness of the Operating Partnership’s $0.9 million Paycheck Protection Program loan in the second quarter of 2021, which was applied as a non-recurring credit of compensation costs previously reimbursed between the Partnership and the Operating Partnership, partially offset by lower information technology project costs in the second quarter and first six months of 2022 when compared to higher oil and natural gas prices and sales volumes.the same periods of 2021.

Net cash provided by operating activities increased 45%139% from $21,563,000 during the first ninesix months of 20162021 to $31,274,000 during the same period of 2017.2022. The changeincrease is mainly driven byprimarily a result of higher oilRoyalties revenue receipts, net of operating costs, including production taxes, and natural gas sales prices. Net cash provided by investing activities increased from $0 to $331,000 mainly due to the cash contributed with the acquisition of royalty interests.higher NPI payment receipts.

In an effort to provide the reader with information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the weighted 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 contract terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between our 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 purchasers’ prior period adjustments.

Cash receipts attributable to our Royalty Properties during the thirdsecond quarter of 20172022 totaled approximately $10,000,000. These$33.9 million. Approximately 74% of these receipts generally reflect oil sales during June 2017March 2022 through August 2017May 2022 and natural gas sales during May 2017February 2022 through July 2017.April 2022, and approximately 26% from prior sales periods. The weighted average indicated prices for oil and natural gas sales received during the 2017 third quartercash receipts attributable to the Royalty Properties during the second quarter of 2022 were $41.36/$89.14/bbl and $2.75/$4.59/mcf, respectively.

Cash receipts attributable to our NPIsNet Profits Interest during the thirdsecond quarter of 20172022 totaled approximately $1,100,000. These$5.1 million. Approximately 68% of these receipts generally reflect oil and natural gas sales during February 2022 through April 2022, and approximately 32% from the properties underlying the NPIs during May 2017 through July 2017.prior sales periods. The weighted average indicated prices for oil and natural gas sales receivedcash receipts attributable to the NPI properties during the 2017 thirdsecond quarter attributable to our NPIsof 2022 were $38.89/$81.42/bbl and $2.75/$5.31/mcf, respectively.

On June 28, 2017, the Partnership executed a definitive agreement to acquire producing and nonproducing mineral and royalty interests located in Glasscock, Howard, Martin, Midland, Reagan and Upton Counties, Texas. The properties consist

 The transaction was consummated on June 30, 2017 and was structured as a non-taxable contribution and exchange. At the closing, in addition to conveying their interests to the Partnership, the contributing parties delivered funds in an amount equal to their cash receipts during the period from April 1, 2017 through June 30, 2017 and attributable to production on the subject properties on or after September 1, 2016, amounting to approximately $614,000, and the Partnership issued an aggregate of 1,604,343 common units of the Partnership to the contributing parties.

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital, on both a short-term and long-term basis, are our cash flowsflows from the NPIsRoyalty Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from Royalty Properties. Our onlyProperties 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 are the distributions to our unitholders,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 ourthe 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 paymentspayment of expenses. Because mostmany 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 Note 4 of5 to the Notes to theunaudited Condensed Consolidated Financial Statements included in “Item 1 – Financial Statements” of this Quarterly Report on Form 10-Q for the amounts and dates ofadditional information regarding cash distributions to unitholders.

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 as of June 30, 2022 are summarized as follows:

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 ourthe 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).

ExpensesWe currently expect to have sufficient liquidity to fund our distributions to unitholders and Capital Expenditures

The operating partnership continues to assess the opportunity to increase production based on prevailing market conditions in Oklahoma with techniquesoperations despite potential material uncertainties that may include fracture treating, deepening, recompleting,impact us as a result of the spread of COVID-19 and drilling. Costs vary widelyany ongoing variants and are not predictable as each effort requires specific engineering. Such activities by the operating partnership could influence the amount we receive from the NPIs.

The operating partnership owns and operates the wells, pipelinesincreased oil and natural gas compressionmarket volatility caused by the Russian invasion of Ukraine and dehydration facilities locatedthe recent rise in Oklahoma. The operating partnership does not anticipate incurring significant expenseinflation and interest rates. Although demand and market prices for oil and natural gas have remained strong due to replace these facilities at this time. These capitalthe rising energy use and worldwide shortage of oil due to sanctions implemented on Russia, 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, along with the military conflict between Russia and Ukraine 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 are reflected inwere to increase significantly, our cash flows and liquidity could be reduced. Despite recent improvements, the NPI paymentscurrent economic environment is volatile, and therefore, we receive fromcannot predict the operating partnership.

In 1998, Oklahoma regulations removed production quantity restrictions inultimate impact that COVID-19 or the Guymon-Hugoton fieldongoing military conflict between Russia and did not address efforts by third parties to persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Infill drilling could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable and could influence the amount we receive from the NPIs. The operating partnership believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future.Ukraine will have on our liquidity or cash flows.

Liquidity and Working Capital

Cash and cash equivalents totaled $11,557,000$43.0 million at SeptemberJune 30, 20172022 and $8,212,000$28.3 million at December 31, 2016.2021.

Critical Accounting Policies and Estimates

We utilize the full cost methodAs of accounting for costs relatedJune 30, 2022, there have been no significant changes to our oilcritical accounting policies and natural gas properties. Under this method, all such costs are capitalized and amortizedrelated estimates previously disclosed in our 2021 Annual Report 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, however, 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 full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. 

The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers may reach different conclusions as to estimated quantities of natural gas or crude oil reserves based on the same information. Our reserve estimates are prepared by independent consultants. The passage of time provides more qualitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that 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.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 and NPI properties 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.

item 3.             Quantitative and Qualitative Disclosures About Market Risk

The following information provides quantitative and qualitative information about our potential exposures to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates and currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses but, rather, indicators of possible losses.Form 10-K.

Market Risk Related to Oil and Natural Gas Prices

Not applicable.

Essentially all of our assets and sources of income are from Royalty Properties and NPIs, which generally entitle us to receive a share of the proceeds based on oil and natural gas production from those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices. Pricing for oil and natural gas production has been unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations.

Absence of Interest Rate and Currency Exchange Rate Risk

We do not anticipate having a credit facility or incurring any debt other than trade debt. Therefore, we do not expect interest rate risk to be material to us. We do not anticipate engaging in transactions in foreign currencies that could expose us to foreign currency related market risk.

item

ITEM 4.            Controls and Procedures

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective.

Changes in Internal ControlsControl

There were no changes in our internal controls (ascontrol over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended SeptemberJune 30, 20172022 that have materially affected, or are reasonably likely to materially affect, our internal controlscontrol over financial reporting.

PART II– OTHER INFORMATION

Item

ITEM 1.             Legal Proceedings

LEGAL PROCEEDINGS

The Partnership and the operating partnershipOperating Partnership are involved in legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes,, and none of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.

There have been no material changes to the Partnership’s risk factors as disclosed in Item 1A of Part I of the Partnership’s annual report on Form 10-K for the year ended December 31, 2021, as supplemented and updated by the Partnership’s quarterly report on Form 10-Q for the quarter ended March 31, 2022.

ITEM 2.

ITEM 6.     ISSUER PURCHASES OF EQUITY SECURITIES

EXHIBITS