The accompanying notes are an integral part of these condensed consolidated financial statements

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERSHIP CAPITAL

.(In Thousands)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated financial statements.

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated financial statements.

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1     Basis of Presentation:

Dorchester Minerals, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership that was formed in December 2001, and commenced operations on January 31, 2003. The unaudited condensed consolidated financial statements include the accounts of Dorchester Minerals, L.P.the Partnership and its wholly-owned subsidiaries Dorchester Minerals Oklahoma LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, and Dorchester-Maecenas GP LLC. All significant intercompany balancesLLC, The Buffalo Co., A Limited Partnership, and transactions have been eliminated in consolidation.DMLPTBC GP LLC.

The accompanying unaudited condensed consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal and recurring adjustments unless indicated otherwise) that are, in the opinion of management, necessary for the fair statementpresentation of our financial position and operating results for the interim period. Interim period results are not necessarily indicative of the results for the calendar year. See “Management’s Discussion and AnalysisFor more information regarding limitations on the forward-looking statements contained herein, see page 1 of Financial Condition and Results of Operations” for additional information. Per-unitthis Quarterly Report on Form 10-Q. Per unit information is calculated by dividing the income or loss applicable to holders of ourthe Partnership’s common units by the weighted average number of units outstanding. The Partnership has no0 potentially dilutive securities and, consequently, basic and dilutivediluted income per unit do not differ. These interimThe accompanying unaudited condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report2020 Annual Report on Form 10-K for the year ended December 31, 2016.10-K.

Fair Value of Financial Instruments- The carrying amount of cash and cash equivalents, trade receivables and payables approximates fair value becauseaccompanying unaudited condensed consolidated financial statements include the consolidated results of the short maturityPartnership. All significant intercompany balances and transactions have been eliminated in consolidation.

The preparation of those instruments. These estimated fair values may not be representativefinancial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of actual valuesassets and liabilities and disclosure of contingent assets and liabilities at the date of the financial instrumentsstatements 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.

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 thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In addition, actions taken by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. The financial results of companies in the oil and natural gas industry have been realizedimpacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates. Although demand and market prices for oil and natural gas have recently increased, due to the rising energy use and the improvement in the U.S. economic activity, we cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

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. This contributed cash, net of capitalized transaction costs of $0.1 million, is included in the net cash contributed in acquisition on the condensed consolidated statement of cash flows for the six months ended June 30, 2021. The condensed consolidated balance sheet as of quarter close or that will be realizedJune 30, 2021 includes $11.9 million of net oil and natural gas properties acquired in the future.transaction.

2     Commitments

On September 30, 2020, the Partnership and Contingencies: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. Final net proceeds from the sale were subject to customary holdbacks and post-closing adjustments.

The Partnership and Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner,General Partner, 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 our consolidated financial position, cash flows, or operating results.

 Operating Leases - We have entered into an operating lease agreement in the ordinary course of our business activities. The third amendment to our office lease was signed on April 17, 2017, for a term of 129 months beginning June 1, 2018. The lease is for our office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, and now expires in 2029. Under the third amendment to the office lease, monthly rental payments will range from $25,000 - $30,000 and the Partnership will receive a tenant improvement allowance of approximately $700,000. The Partnership recognizes a deferred rent liability for the rent escalations when the amount of straight-line rent exceeds the lease payments, and reduces the deferred rent liability when the lease payments exceed the straight-line rent expense. For the tenant improvement allowance, the Partnership will record a deferred rent liability and will amortize the deferred rent over the lease term as a reduction to rent expense once in use.

3     Acquisition for Common Units:On June 30, 2017, pursuant to a Contribution, Exchange and Purchase Agreement with DSD Royalty, LLC, a Texas limited liability company (“DSD”), the Partnership acquired producing and nonproducing royalty and mineral interests located in the Midland Basin in exchange for consideration valued at approximately $23,183,000, half in cash (the “Cash Consideration”) and half in common units representing limited partner interests in the Partnership (“Common Units”), based on a price of $14.98 per Common Unit (calculated based on the average closing price of Common Units during the period beginning 15 trading days immediately prior to the closing date and ending two trading days prior to the closing date) (the “DSD Agreement”). Prior to the closing of the DSD Agreement, the Partnership entered into a Participation Agreement with certain officers of the Partnership and entities affiliated with certain officers and directors of the Partnership (the “Participants”), pursuant to which the Partnership agreed to assign an undivided 50% interest in its rights under the DSD Agreement to the Participants in exchange for the Participants’ assumption of the obligation to pay the Cash Consideration on behalf of the Partnership (the “Participation Agreement”). On June 30, 2017, in connection with the closing of the DSD Agreement, the Participants contributed to the Partnership their respective assets received pursuant to the Participation Agreement in exchange for common units of the Partnership based on a price of $14.98 per Common Unit (calculated in the same manner as the price of Common Units issued pursuant to the DSD Agreement) pursuant to Contribution and Exchange Agreements with the Partnership (the “Participant Contribution Agreements”). In accordance with the transactions contemplated by the DSD Agreement and the Participant Contribution Agreements, the Partnership issued to DSD and the Participants an aggregate of 1,604,343 Common Units pursuant to the Partnership’s registration statements on Form S-4. After the issuance, 6,395,657 Common Units remain available under the Partnership’s registration statements on Form S-4.

4       Distributions to Holders of Common Units:Unitholder cash distributions per common unit since 2015 have been:

Distributions beginning withThe distribution for 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 distribution2021 will be paid on November 9, 2017. Fourth quarter distributions shown above are paid in35,404,774 common units. The distribution for the first calendarsecond quarter of the following year. 2020 was paid on 34,679,774 common units. The second quarter 2021 distribution of $0.480528 per common unit will be paid on August 12, 2021. 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 2014-09.2021.

 In February 2016, the FASB issued ASU 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has lease commitments of approximately $3 million that we believe would be subject to capitalization under ASU 2016-02. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than our current obligations. Accordingly, at this time we cannot estimate the amount that will be capitalized when this standard is adopted.

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.

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 574581 counties and parishes in 2526 states.

 WeAs of June 30, 2021, 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 haveThe NPI has 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, 2021, 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.$1.7 million.

Commodity Price Risks

The pricing of oil and natural gas sales is primarily determined by supply and demand in the 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 and 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 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 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. 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. As a result, oil and natural gas market prices have improved in response to the increase in demand. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices. However, 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 of the COVID-19 pandemic continues. The COVID-19 pandemic continues to be dynamic and evolving, and its ultimate duration and effects remain uncertain.

Results of Operations

ThreeAcquisition of Royalty Properties

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 issued pursuant to the Partnership's registration statement on Form S-4. After the issuance, 29,275,000 units remain available for issuance under the Partnership's available registration statements. 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. This contributed cash, net of capitalized transaction costs of $0.1 million, is included in net cash contributed in acquisition on the condensed consolidated statement of cash flows for the six months ended June 30, 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. Final net proceeds from the sale were subject to customary holdbacks and post-closing adjustments. Customary holdbacks of $0.2 million were paid to the Partnership and are included in proceeds from the sale of oil and natural gas properties 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, 2021 as compared to Three and Nine Six Months Ended June 30,2020September30, 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.

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

Oil sales volumes attributable to our Royalty Properties duringremained consistent from the thirdsecond quarter increased 27% from 163 mbbls in 2016 to 207 mbbls inof 2020 versus the same period of 2017. Oil2021. This is primarily the result of lower suspense releases on new wells in the Bakken region and Rockies in the second quarter of 2021 compared to the same period of 2020 and natural production declines in the Bakken region and Mid-Continent, offset by increased Permian Basin production due to higher suspense releases on new wells in the second quarter of 2021 compared to the same period of 2020. The increase in oil sales volumes attributable to our Royalty Properties from the first ninesix months of 2016 increased 26% from 451 mbbls2020 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 20162021 is mainlyprimarily a result of increased Permian Basin production due to higher suspense releases on new wells and prior period adjustments, partially offset by lower suspense releases on new wells in the Bakken region and Rockies and natural production declines in the Bakken region and Mid-Continent. The increase in natural gas sales volumes attributable to our Royalty Properties from the second quarter of 2020 to the same period of 2021 is primarily a result of higher suspense releases on new wells.wells in the Permian Basin and increased production in the Permian Basin and Barnett Shale, partially offset by lower suspense releases on new wells in the Rockies and decreased production in East Texas. Natural gas sales volumes attributable to our Royalty Properties duringremained relatively consistent from the third quarter increased 25% from 775 mmcf in 2016first six months of 2020 to 967 mmcf in the same period of 2017. Natural gas sales volumes during2021. This is primarily the first nine months increased 9% from 2,461 mmcf in 2016 to 2,681 mmcfresult of higher suspense releases on new wells in the same period of 2017. The increase in volumes during the third quarterPermian Basin and first nine months of 2017 compared to the same periods of 2016 is mainly a result of increased production in the Permian Basin partiallyand Barnett Shale being largely offset by lower suspense releases on new wells in the Rockies and decreased production in other areas of Texas.

The decrease in oil sales attributable to our NPI properties from the second quarter of 2020 to the same period of 2021 is primarily a result of lower suspense releases for new wells in the Bakken region, decreased production in the Fayetteville Shale play.

Oil sales volumes attributable to our NPIs during the third quarterPermian Basin, and first nine months of 2016 were 84 mbbls and 307 mbbls, respectively, resulting in decreases of 29% and 35% to 60 mbbls and 200 mbbls, respectively, during the same periods of 2017.natural production declines. The decrease in oil sales volumes attributable to our NPI properties from the first six months of 2020 to the same period of 2021 is mainly due toprimarily a result of lower suspense releases for new wells in the Bakken region and Permian Basin and decreased production across all regions after 2020 curtailments were restored. The decrease in natural reservoir declines. Natural gas sales volumes attributable to our NPIs duringNPI properties from the second quarter and first six month of 2020 to the same periods of 2021 is primarily the result of the absence of production from the Hugoton Field in the second quarter and first six months of 2021 due to the Hugoton NPI divestiture in the third quarter of 2020, partially offset by increased 5% from 599 mmcf in 2016 to 631 mmcfproduction in the same period of 2017Bakken region and increased Fayetteville Shale production due to a higher number of suspense releases in 2017. During the first nine months of 2017, NPI natural gas volumes decreased 10% from 1,996 mmcf in 2016 to 1,799 mmcf in the sameprior period of 2017. The decrease in gas sales volumes is mainly due to natural reservoir declines in addition to the lower amount of suspense releases in the first quarter of 2017 as compared to the first quarter of 2016.adjustments.

Our third quarter net operatingOperating revenues increased 17%215% from $10,679,000$6.8 million during 2016the second quarter of 2020 to $12,480,000$21.4 million during the same period of 2017. Current quarter2021. The increase in royalty revenues is primarily due toa result of higher Royalty Properties natural gas sales volumes, higher Royalty Properties oil and natural gas sales prices, partially offset by a decrease in both net profits interests income and lease bonus income versushigher NPI revenues. Operating revenues also increased 76% from $22.3 million during the prior year. Our first ninesix months net operating revenues increased 41% from $26,814,000 during 2016of 2020 to $37,760,000$39.2 million during the same period of 2017. These increases are2021. The increase is primarily a result of an increase in royalty revenues resulting from higher Royalty Properties oil and natural gas pricessales volumes and sales volumes.prices.

ThirdOperating costs, including production taxes, increased 14% from $1.4 million during the second quarter operating costs and expenses increased 46% from $902,000 during 2016of 2020 to $1,320,000$1.6 million during the same period of 2017. Our2021. Operating costs, including production taxes, also increased 14% from $2.8 million during the first ninesix months operating costs increased 54% from $2,180,000 during 2016of 2020 to $3,358,000$3.2 million during the same period of 2017.2021. The increases in both periods are primarily a result of higher production taxes due to higher natural gas sales volumes and higher oil and natural gas sales prices.prices, partially offset by lower ad valorem taxes.

GeneralDepreciation, depletion and administrative expenses of $1,050,000amortization decreased 14% from $2.9 million during the thirdsecond quarter of 2016 increased 9%2020 to $1,141,000$2.5 million during the same period of 2017 primarily as a result of costs related to our office remodel. General2021. Depreciation, depletion and administrative expenses of $3,967,000amortization also decreased 24% from $6.3 million during the first ninesix months of 2016 decreased 5% compared2020 to $3,764,000$4.8 million 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 compared to the same period of 2016.

Depletion and amortization costs of $2,080,000 during the third quarter of 2016 increased 34% 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 2017.2021. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves.reserves, including acquisitions and divestitures.

ThirdGeneral and administrative expenses decreased 46% from $1.3 million during the second quarter net income allocableof 2020 to common units increased 8% from $6,417,000 during 2016 to $6,951,000$0.7 million during the same period of 2017 mainly due2021. General and administrative expenses also decreased 9% from $3.2 million during the first six months of 2020 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$2.9 million during the same period of 2017.2021. The increase is mainlydecreases are primarily a result of lower compensation expenses due to the 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. The lower compensation costs for the second quarter and first six months of 2021 were partially offset by higher royalty income dueinformation technology project costs when compared to higher oil and natural gas prices and sales volumes.the same periods of 2020.

Net cash provided by operating activities increased 45%7% from $21,563,000$26.4 million during the first ninesix months of 20162020 to $31,274,000$28.2 million during the same period of 2017.2021. The changeincrease is mainly driven byprimarily a result of higher oil and natural gas sales prices. Net cash provided by investing activities increased from $0 to $331,000 mainly dueRoyalties revenue receipts, net of operating costs, for the first six months of 2021 compared to the cash contributed withsame period of 2020, partially offset by lower NPI payment receipts for the acquisitionfirst six months of royalty interests.2021 compared to the same period of 2020.

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 20172021 totaled approximately $10,000,000. These$15.0 million. Approximately 82% of these receipts generally reflect oil sales during June 2017March 2021 through August 2017May 2021 and natural gas sales during May 2017February 2021 through July 2017.April 2021, and approximately 18% 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 2021 were $41.36/$53.33/bbl and $2.75/$3.29/mcf, respectively.

Cash receipts attributable to our NPIsNet Profits Interests during the thirdsecond quarter of 20172021 totaled approximately $1,100,000. These$3.4 million. Approximately 69% of these receipts generally reflect oil and natural gas sales during February 2021 through April 2021, and approximately 31% 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 2021 were $38.89/$49.29/bbl and $2.75/$3.36/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

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital are our cash flowsflows from the NPIsNPI and the Royalty Properties. Our onlypartnership 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 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.

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 COVID-19 pandemic and drilling. Costs vary widely 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, pipelinescontinued oil and natural gas compressionmarket volatility. Although demand and dehydration facilities locatedmarket prices for oil and natural gas have recently increased due to the rising energy use and the improvements in Oklahoma. The operating partnership does not anticipate incurring significant expensethe U.S. economic activity, we cannot predict events that may lead to replace these facilities at this time. These capitalfuture 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 ongoing evolution of the COVID-19 pandemic, including the spread of its variants, which are beyond our control. If market conditions were to change due to declines in oil prices or uncertainty created by the ongoing COVID-19 pandemic, 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 in the Guymon-Hugoton field 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.ultimate impact on our liquidity or cash flows.

Liquidity and Working Capital

Cash and cash equivalents totaled $11,557,000$20.5 million at SeptemberJune 30, 20172021 and $8,212,000$11.2 million at December 31, 2016.2020.

Critical Accounting Policies

We utilize the full cost methodAs of accounting for costs relatedJune 30, 2021, 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 2020 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.

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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, 20172021 that have materially affected, or are reasonably likely to materially affect, our internal controlscontrol over financial reporting.

PART II– OTHER INFORMATION

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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.

ITEM 2.     ISSUER PURCHASES OF EQUITY SECURITIESThere have been no material changes to the Partnership's risk factors as disclosed in “Item 1A – Risk Factors” of Part I of the Partnership's annual report on Form 10-K for the year ended December 31, 2020.