What changed in this filing

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Item 1. Financial Statements

2021-11-04 compared with 2021-08-05 · 113 added, 72 removed, 256 unchanged (42% of the section changed)

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(In Thousands)

September 30,

Current assets:

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Trade and other receivables

10,145  

Net profits interest receivable - related party

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Three Months Ended

Six Months Ended

Nine Months Ended

September 30,

Net operating revenues:

$ 20,031  

$ 10,740  

$ 51,172  

$ 27,195  

Net profits interests

10,692  

Total net operating revenues

23,969  

12,545  

63,119  

34,816  

Costs and expenses:

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Total costs and expenses

16,778  

19,244  

$ 18,031  

$ 5,619  

$ 46,341  

$ 15,572  

Allocation of net income:

General partner

$ 1,579  

$ 17,400  

$ 5,427  

$ 44,762  

$ 15,082  

Net income per common unit (basic and diluted)

$ 0.49  

$ 0.16  

$ 1.28  

$ 0.43  

Weighted average basic and diluted common units outstanding

35,405  

34,680  

34,927  

34,680  

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

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(In Thousands)

Three Months Ended June 30, 2020

Balance at April 1, 2020

$ 1,041  

Three Months Ended September 30, 2020

Balance at July 1, 2020

$ 91,662  

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Distributions ( $0.226318 per Unit)

Balance at June 30, 2020

$ 91,662  

$ 92,291  

Balance at September 30, 2020

$ 89,240  

Three Months Ended June 30, 2021

Balance at April 1, 2021

$ 89,859  

34,680  

Three Months Ended September 30, 2021

Balance at July 1, 2021

$ 104,681  

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35,405  

Acquisition of assets for units

17,400  

1 unchanged sentence

Distributions ( $0.480528 per Unit)

Balance at June 30, 2021

Balance at September 30, 2021

$ 105,068  

1 unchanged sentence

35,405  

Six Months Ended June 30, 2020

Nine Months Ended September 30, 2020

Balance at January 1, 2020

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34,680  

15,082  

15,572  

Distributions ( $1.065451 per Unit)

Balance at June 30, 2020

Balance at September 30, 2020

$ 89,240  

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34,680  

Six Months Ended June 30, 2021

Nine Months Ended September 30, 2021

Balance at January 1, 2021

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Distributions ( $1.026229 per Unit)

Balance at June 30, 2021

Balance at September 30, 2021

$ 105,068  

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(In Thousands)

Six Months Ended

Nine Months Ended

September 30,

Net cash provided by operating activities

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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.

However, the COVID- 19 Delta variant emerged in March 2021 and became highly transmissible in July 2021, which contributed to additional pricing volatility during 2021 to date.

The financial results of companies in the oil and natural gas industry have been impacted 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.

Although demand and market prices for oil and natural gas have recently increased, due to the rising energy use and the improvement in 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.

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 are continuing to closely monitor the overall impact and the evolution of the COVID- 19 pandemic, including the spread of its variants, along with future OPEC actions on all aspects of our business, including how these events may impact our future operations, financial results, liquidity, employees and operators.

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, particularly if the resurgence of the COVID- 19 pandemic continues.

We cannot predict the long-term impact of these events on our liquidity, financial position, results of operations or cash flows due to uncertainties including the severity of COVID- 19 and the effect the virus will have on the demand for oil and natural gas.

We are continuing to closely monitor the overall impact and the evolution of the COVID- 19 pandemic, including the ongoing spread of any variants, along with future OPEC actions on all aspects of our business, including how these events may impact our future operations, financial results, liquidity, employees, and operators.

We cannot predict the long-term impact of these events on our liquidity, financial position, results of operations or cash flows due to uncertainties including the severity of COVID- 19 or any of the ongoing variants, and the effect the virus will have on the demand for oil and natural gas.

These situations remain fluid and unpredictable, and we are actively managing our response.

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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 June 30, 2021 includes $ 11.9 million of net oil and natural gas properties acquired in the transaction.

During the three months ended September 30, 2021, the Partnership had final settlement net cash receipts from the transaction of $ 0.3 million.

The contributed cash and final settlement net cash receipts, net of capitalized transaction costs of $ 0.1 million, are included in the net cash contributed in acquisition on the condensed consolidated statement of cash flows for the nine months ended September 30, 2021.

The condensed consolidated balance sheet as of September 30, 2021 includes $ 11.5 million of net oil and natural gas properties acquired in the transaction.

Net Profits Interest Divestiture

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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 condensed consolidated income statements for the three and nine month periods ended September 30, 2020.

Final net proceeds from the sale were subject to customary holdbacks and post-closing adjustments.

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Distributions to Holders of Common Units

The distribution for the second quarter of 2021 will be paid on 35,404,774 common units.

The distribution for the second quarter of 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 third quarter cash distribution to be paid by November 14, 2021.

The distribution for the third quarter of 2021 will be paid on 35,404,774 common units.

The distribution for the third quarter of 2020 was paid on 34,679,774 common units.

The third quarter 2021 distribution of $ 0.507608 per common unit will be paid on November 10, 2021.

Our partnership agreement requires the fourth quarter cash distribution to be paid by February 14, 2022.

MANAGEMENT ’

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We currently own Royalty Properties in 581 counties and parishes in 26 states.

As of June 30, 2021, we own a net profits overriding royalty interest (referred to as the Net Profits Interest, or “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.

As of September 30, 2021, we own a net profits overriding royalty interest (referred to as the Net Profits Interest, or “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 receive monthly payments from the NPI equaling 96.97% of the net profits actually realized by the Operating Partnership from these properties in the preceding month.

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In the event the NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership.

From a cash perspective, as of June 30, 2021, the NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, equaling cash on hand of $1.7 million.

From a cash perspective, as of September 30, 2021, the NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, equaling cash on hand of $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.

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 and the terms and conditions on which such volumes are marketed and sold.

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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, the Delta variant emerged in March 2021 and became highly transmissible in July 2021, 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.

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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.

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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.

During the three months ended September 30, 2021, the Partnership had final settlement net cash receipts from the transaction of $0.3 million.

The contributed cash and final settlement net cash receipts, net of capitalized transaction costs of $0.1 million, are included in the net cash contributed in acquisition on the condensed consolidated statement of cash flows for the nine months ended September 30, 2021.

Net Profits Interest Divestiture

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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 condensed consolidated income statements for the three and nine month periods ended September 30, 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 Six Months Ended June 30, 2021 as compared to Three and Six Months Ended June 30,  

Three and Nine Months Ended September 30, 2021 as compared to Three and Nine Months Ended September 30,  

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.

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Three Months Ended

Six Months Ended

Nine Months Ended

September 30,

Accrual basis sales volumes:

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NPI oil sales (mbbls)

Accrual basis weighted average sales price:

Accrual basis average sales price:

Royalty properties natural gas sales ($/mcf)

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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 remained consistent from the second quarter of 2020 versus the same period of 2021.

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 six months of 2020 to the same period of 2021 is primarily 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 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 remained relatively consistent from the first six months of 2020 to the same period of 2021.

This is primarily the result of higher suspense releases on new wells in the Permian Basin and increased production in the Permian Basin and 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 Permian Basin, and 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 primarily 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 gas sales volumes attributable to our NPI 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 production in the Bakken region and increased Fayetteville Shale production due to higher prior period adjustments.

Operating revenues increased 215% from $6.8 million during the second quarter of 2020 to $21.4 million during the same period of 2021.

The increase is primarily a result of higher Royalty Properties natural gas sales volumes, higher Royalty Properties oil and natural gas sales prices, and higher NPI revenues.

Operating revenues also increased 76% from $22.3 million during the first six months of 2020 to $39.2 million during the same period of 2021.

The increase is primarily a result of higher Royalty Properties oil and natural gas sales volumes and sales prices.

Operating costs, including production taxes, increased 14% from $1.4 million during the second quarter of 2020 to $1.6 million during the same period of 2021.

Operating costs, including production taxes, also increased 14% from $2.8 million during the first six months of 2020 to $3.2 million during the same period of 2021.

The increases are primarily a result of higher production taxes due to higher natural gas sales volumes and higher oil and natural gas sales prices, partially offset by lower ad valorem taxes.

Depreciation, depletion and amortization decreased 14% from $2.9 million during the second quarter of 2020 to $2.5 million during the same period of 2021.

Depreciation, depletion and amortization also decreased 24% from $6.3 million during the first six months of 2020 to $4.8 million during the same period of 2021.

Oil sales volumes attributable to our Royalty Properties remained consistent from the third quarter of 2020 versus the same period of 2021.

This is primarily a result of 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, offset by lower suspense releases on new wells in the Rockies in the third quarter of 2021 compared to the same period of 2020 and natural production declines in the Bakken region, Rockies, and Mid-Continent.

Oil sales volumes attributable to our Royalty Properties remained consistent from the first nine months of 2020 to the same period of 2021.

This is primarily 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.

Natural gas sales volumes attributable to our Royalty Properties remained consistent from the third quarter of 2020 versus the same period of 2021.

This is primarily a result of increased Permian Basin and Bakken region production and higher suspense releases on new wells in the Permian Basin and Mid-Continent in the second quarter of 2021 compared to the same period of 2020, offset by lower suspense releases on new wells in the Southeast in the second quarter of 2021 compared to the same period of 2020 and natural production declines in the Rockies and South Texas.

Natural gas sales volumes attributable to our Royalty Properties remained consistent from the first nine months of 2020 to the same period of 2021.

This is primarily a result of higher suspense releases on new wells in the Permian Basin and increased production in the Permian Basin and 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 third quarter of 2020 to the same period of 2021 is primarily a result of decreased production in the Permian Basin and natural production declines in the Bakken region and Mid-Continent.

The decrease in oil sales volumes attributable to our NPI properties from the first nine months of 2020 to the same period of 2021 is primarily a result of lower suspense releases for new wells in the Bakken region and Permian Basin and decreased production across all regions after the 2020 curtailments were restored.

The decrease in natural gas sales volumes attributable to our NPI properties from the third quarter and first nine months of 2020 to the same periods of 2021 is primarily the result of the absence of production from the Hugoton Field in the third quarter and first nine months of 2021 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.

Operating revenues increased 92% from $12.5 million during the third quarter of 2020 to $24.0 million during the same period of 2021.

The increase is primarily a result of higher Royalty Properties oil sales volumes, higher Royalty Properties oil and natural gas sales prices, and higher NPI revenues.

Operating revenues also increased 81% from $34.8 million during the first nine months of 2020 to $63.1 million during the same period of 2021.

The increase is primarily a result of higher Royalty Properties oil and natural gas sales volumes and sales prices and higher NPI revenues.

Operating costs, including production taxes, increased 40% from $1.5 million during the third quarter of 2020 to $2.1 million during the same period of 2021.

The increase is primarily a result of higher production taxes due to higher oil sales volumes and higher oil and natural gas sales prices.

Operating costs, including production taxes, increased 23% from $4.3 million during the first nine months of 2020 to $5.3 million during the same period of 2021.

The increase is primarily a result of higher production taxes due to higher natural gas and oil sales volumes and higher oil and natural gas sales prices, partially offset by lower ad valorem taxes.

Depreciation, depletion and amortization decreased 9% from $3.2 million during the third quarter of 2020 to $2.9 million during the same period of 2021.

Depreciation, depletion and amortization also decreased 19% from $9.5 million during the first nine months of 2020 to $7.7 million during the same period of 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 46% from $1.3 million during the second quarter of 2020 to $0.7 million during the same period of 2021.

General and administrative expenses also decreased 9% from $3.2 million during the first six months of 2020 to $2.9 million during the same period of 2021.

The decreases 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 information technology project costs when compared to the same periods of 2020.

Net cash provided by operating activities increased 7% from $26.4 million during the first six months of 2020 to $28.2 million during the same period of 2021.

The increase is primarily a result of higher Royalties revenue receipts, net of operating costs, for the first six months of 2021 compared to the same period of 2020, partially offset by lower NPI payment receipts for the first six months of 2021 compared to the same period of 2020.

General and administrative expenses decreased 59% from $2.2 million during the third quarter of 2020 to $0.9 million during the same period of 2021.

The decrease is primarily a result of non-recurring Hugoton NPI divestiture transaction costs in the third quarter of 2020 and lower compensation expenses due to the forgiveness of the Operating Partnership’s $0.8 million Paycheck Protection Program loan in the third 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 higher information technology software costs for the third quarter of 2021 compared to the same period of 2020.

General and administrative expenses decreased 31% from $5.5 million during the first nine months of 2020 to $3.8 million during the same period of 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, and non-recurring Hugoton NPI divestiture transaction costs in the third quarter of 2020, partially offset by higher information technology software and public company compliance and insurance costs for the first nine months of 2021 compared to the same period of 2020.

Net cash provided by operating activities increased 48% from $32.0 million during the first nine months of 2020 to $47.5 million during the same period of 2021.

The increase is primarily a result of higher Royalties revenue receipts, net of operating costs, including production taxes, for the first nine months of 2021 compared to the same period of 2020, partially offset by lower NPI payment receipts for the first nine months of 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 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.

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prior period adjustments.

Cash receipts attributable to our Royalty Properties during the second quarter of 2021 totaled $15.0 million.

Approximately 82% of these receipts reflect oil sales during March 2021 through May 2021 and natural gas sales during February 2021 through April 2021, and approximately 18% from prior sales periods.

The average indicated prices for oil and natural gas sales cash receipts attributable to the Royalty Properties during the second quarter of 2021 were $53.33/bbl and $3.29/mcf, respectively.

Cash receipts attributable to our Net Profits Interests during the second quarter of 2021 totaled $3.4 million.

Approximately 69% of these receipts reflect oil and natural gas sales during February 2021 through April 2021, and approximately 31% from prior sales periods.

The average indicated prices for oil and natural gas sales cash receipts attributable to the NPI properties during the second quarter of 2021 were $49.29/bbl and $3.36/mcf, respectively.

Cash receipts attributable to our Royalty Properties during the third quarter of 2021 totaled $17.3 million.

Approximately 77% of these receipts reflect oil sales during June 2021 through August 2021 and natural gas sales during May 2021 through July 2021, and approximately 23% from prior sales periods.

The average indicated prices for oil and natural gas sales cash receipts attributable to the Royalty Properties during the third quarter of 2021 were $59.96/bbl and $3.03/mcf, respectively.

Cash receipts attributable to our Net Profits Interests during the third quarter of 2021 totaled $3.3 million.

Approximately 77% of these receipts reflect oil and natural gas sales during May 2021 through July 2021, and approximately 23% from prior sales periods.

The average indicated prices for oil and natural gas sales cash receipts attributable to the NPI properties during the third quarter of 2021 were $59.42/bbl and $3.26/mcf, respectively.

Liquidity and Capital Resources

Capital Resources

Our primary sources of capital are our cash flows from the NPI and the Royalty Properties.

Our primary sources of capital, on both a short-term and long-term basis, are our cash flows from the NPI and the Royalty Properties.

Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from NPIs and the Royalty Properties (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves.

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(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 COVID-19 pandemic and continued oil and natural gas market volatility.

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 use and the improvements in the U.S.

economic activity, 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 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 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.

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 totaled $20.5 million at June 30, 2021 and $11.2 million at December 31, 2020.

Cash and cash equivalents totaled $22.3 million at September 30, 2021 and $11.2 million at December 31, 2020.

Critical Accounting Policies

As of June 30, 2021, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2020 Annual Report on Form 10-K.

As of September 30, 2021, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2020 Annual Report on Form 10-K.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 1. Financial Statements