What changed in this filing

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Item 7. Management’s Discussion and Analysis

2020-12-03 compared with 2019-12-03 · 341 added, 425 removed, 166 unchanged (82% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations .

COVID-19 and the resulting pandemic continues to have a significant impact on local, state, national and global economies.

The actions taken by governments, as well as businesses and individuals, to limit the spread and overcome the virus has significantly disrupted normal activities throughout the Company's service territory.

Management has updated and implemented its pandemic plan to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees.

Additionally, the Company regularly evaluates its pandemic plan for adherence to new rules and regulations issued by the Department of Labor and the Occupational Safety and Health Administration regarding workplace safety.

Since the beginning of the pandemic, Resources has been deemed an essential entity by virtue of the utility services provided through Roanoke Gas.

As a result of the pandemic, the Company saw a decline in natural gas consumption in most categories of its commercial customers;

however, certain industrial customers have increased gas consumption, primarily for use in their business process, more than offsetting the commercial declines.

The Company’s volume of gas delivered to residential customers has remained relatively consistent with the prior year.

The Company expects a continued overall decline in gas consumption by its commercial customers throughout fiscal 2021.

The SCC issued an order in March 2020, which was extended to October 5, 2020, prohibiting any utility operating in Virginia from disconnecting utility service to customers for non-payment or applying late payment fees to delinquent accounts.

During the special session of the Virginia General Assembly, HB5005 was enacted and extended the above moratorium until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner.

Accordingly, the Company has increased its provision for bad debts, based on information currently available.

Additionally, in April 2020, the SCC issued an order granting potential relief from bad debts and other incremental expenses, directly related to the pandemic.

While the Company is tracking these costs and will file for relief with the SCC as appropriate, the full extent of these costs and the impact to the Company's results of operations and financial position remains unpredictable.

The full extent to which the COVID-19 pandemic will impact the Company depends on future developments, which are highly uncertain and cannot be reasonably predicted, including the duration, scope and severity of the pandemic, the increase or reduction in governmental restrictions to businesses and individuals, the potential resurgence of the virus, as well as the timing and efficacy of a vaccine.

The longer the pandemic continues, the greater the potential negative financial effect on the Company and its customers.

Management believes the economic impact of the pandemic will continue well into calendar 2021.

Cyber attacks are a constant threat to businesses and individuals.

The Company remains focused on these threats and is committed to safeguarding its information technology systems.

These systems contain confidential customer, vendor and employee information as well as important operational financial data.

There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information.

Management continuously monitors access to these systems and believes it has security measures in place to protect these systems from cyber attacks and similar incidents;

however, there can be no guarantee that an incident will not occur.

In the event of a cyber incident, the Company will execute its Security Incident Response Plan.

The Company maintains cyber insurance to mitigate financial costs that may result from a cyber incident.

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,000 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary.

Roanoke Gas also provides certain unregulated services.

As a wholly-owned subsidiary of Resources, Midstream is a 1% member in the Mountain Valley Pipeline, LLC.

As a wholly-owned subsidiary of Resources, Midstream is a more than 1% member in the Mountain Valley Pipeline, LLC.

More information regarding the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below.

The unregulated operations represent less than 2% of revenues and margins of Resources.

The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation.

Roanoke Gas is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines.

FERC regulates prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services.

Roanoke Gas is also subject to other regulations which are not necessarily industry specific.

The unregulated operations represent less than 2% of annual revenues of Resources.

The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines.

FERC regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services.

In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.

More than 98% of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers.

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These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.

The Company has completed the transition to the 21% federal statutory income tax rate as a result of the TCJA that was signed into law in December 2017.

Since the implementation of the new tax rates, the Company has recorded a provision for refund related to estimated excess revenues collected from customers under approved billing rates designed to recover expenses and provide a rate of return based on a federal tax rate of 34%.

Beginning January 1, 2019, Roanoke Gas incorporated the effect of the 21% federal tax rate with the implementation of new non-gas base rates, as filed in its current rate application, and began refunding the excess revenues associated with the change in the tax rate over the subsequent 12-month period.

On October 10, 2018, Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates.

Roanoke Gas implemented the interim non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019.

On January 24, 2020, the SCC issued its final order on the general rate application, granting Roanoke Gas an annualized increase in non-gas base rates of $7.25 million and an authorized rate of return on equity of 9.44%.

As a result, the Company refunded $3.8 million to its customers in March 2020, representing the excess revenues collected plus interest for the difference between the final approved rates and the interim rates billed since January 1, 2019.

The order also directed the Company to write-down $317,000 of ESAC assets that were not subject to recovery under the final order.

In fiscal 2019, the Company completed its transition to the 21% federal statutory income tax rate as a result of the TCJA that was signed into law in December 2017.

Between the enactment of the new tax rates and the Company's implementation of new non-gas rates effective January 1, 2019, the Company was recovering revenues based on a 34% federal income tax rate rather than a 21% federal tax rate.

As a result, during this period, the Company recorded a provision for refund related to estimated excess revenues collected from customers for the difference in non-gas rates derived under the lower federal tax rate and the 34% rate included in non-gas rates.

Roanoke Gas incorporated the effect of the 21% federal income tax rate with the implementation of new non-gas base rates, as filed in its general non-gas rate application, and refunded the excess revenues associated with the change in the tax rate over a 12 month period ending December 2019.

The Company also recorded a regulatory liability related to the excess deferred income taxes on the regulated operations of Roanoke Gas.

These excess deferred income taxes are being

refunded to customers over a 28-year period.

The SCC staff report issued, as part of the audit of the Company's non-gas rate application, indicated no changes to the amounts for excess revenue collected and the excess deferred taxes to be refunded to customers.

The Company expects to complete the refund of the excess revenues by December and will continue to refund the excess deferred taxes over time.

Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.

As mentioned above, the Company currently has a non-gas base rate application pending before the SCC.

Roanoke Gas implemented the non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019.

These non-gas rates are subject to refund pending audit, hearing and a final order issued by the SCC.

On June 28, 2019, the SCC staff issued its report and findings from the audit of the rate application.

In its report, the SCC staff recommended a lower non-gas base rate increase than was requested in the rate application, which is normal and expected.

In addition, the SCC staff recommended a change in rate design between customer base charge and volumetric rates, shifting much of the increase in non-gas base rates from customer base charges to the volumetric components.

At the hearing held in August 2019, management provided additional testimony and rebuttal to certain proposed adjustments in response to the SCC staff report.

After evaluating the adjustments proposed by the SCC staff and the testimony provided at the hearing, management updated its assumptions used in estimating the refund amount included in the financial statements.

The hearing examiner's report and final order from the SCC is not expected until December 2019 or early 2020.

Upon receipt of the final order, the Company will adjust the interim rates to the those approved in the rate order and finalize the rate refund based on the approved rates.

Subsequent to year end, the Company received the hearing examiner's reports.

See Note 15 and the Regulatory and Tax Reform section below for additional information.

The Company is committed to the safe and reliable delivery of natural gas to its customers.

Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines and other system improvements.

In 2017, the Company completed the replacement of all cast iron and bare steel pipe and is continuing its renewal program with other qualified infrastructure replacement programs including the renewal of first generation, pre-1973 plastic pipe.

The Company is also dedicated to the safeguarding of its information technology systems.

These systems contain confidential customer, vendor and employee information as well as important financial data.

There is risk associated with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions, or compromise information.

Management believes it has taken reasonable security measures to protect these systems from cyber attacks and other types of incidents;

however, there can be no guarantee that an incident will not occur.

In the event of a cyber incident, the Company will execute its Security Incident Response Plan.

The Company maintains cyber-insurance coverage to mitigate financial expense that may result from a cyber incident.

These excess deferred income taxes are being refunded to customers over a 28-year period.

Additional information regarding the TCJA and non-gas base rate award is provided under the Regulatory and Tax Reform section below.

As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas, can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders.

In order to mitigate the effect of weather variations and other factors not provided for in the Company's base rates, Roanoke Gas has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on qualified infrastructure investment.

These mechanisms include the SAVE Rider, WNA, ICC revenue and PGA.

These mechanisms include the SAVE Rider, WNA, ICC and PGA.

The Company’s non-gas base rates are designed to allow for the recovery of non-gas related expenses and provide a reasonable return to shareholders.

These rates are determined based on the filing of a formal rate application with the SCC.

These rates are determined based on the filing of a formal non-gas rate application with the SCC.

Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas base rates currently in place.

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The SAVE Plan and Rider provides the Company with the ability to recover costs related to these SAVE qualified infrastructure investments on a prospective basis.

The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provides a return on rate base of the additional capital investments related to improving the Company's infrastructure until such time a formal rate application is filed to incorporate this investment in the Company's non-gas base rates.

Since the Company's previous non-gas base rate application in 2013, SAVE Plan revenues have grown each year corresponding to the level of SAVE qualifying capital investment.

With the filing of the new non-gas base rate application, the SAVE Rider has been reset as the qualified SAVE Plan investment through December 2018 has been incorporated into the current application.

Accordingly, SAVE Plan revenues declined to $1,599,000 in fiscal 2019 compared to $4,469,000 and $3,813,000 for fiscal 2018 and 2017.

Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

until such time a formal rate application is filed to incorporate these investments in the Company's non-gas base rates.

With the implementation of new non-gas rates effective January 1, 2019, the SAVE Rider was reset as the cumulative qualifying SAVE Plan investment through December 31, 2018 was incorporated into the non-gas rate application as part of the new non-gas base rates.

Accordingly, SAVE Plan revenues declined to $1,272,000 in fiscal 2020 from $1,599,000 in fiscal 2019.

Fiscal 2019 included three months of SAVE revenue under the SAVE Plan rates in effect prior to the revenue being incorporated into the new non-gas base rates.

In 2017, the Company completed the replacement of all cast iron and bare steel pipe and is continuing its renewal program under the SAVE Plan and Rider by renewing its first generation, pre-1973 plastic pipe.

Additional information regarding the SAVE Rider is provided under the Regulatory and Tax Reform section.

The WNA reduces the volatility in earnings due to the variability in temperatures during the heating season.

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The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal.

Any billings or refunds related to the WNA are completed following the WNA year end, which runs from April to March.

For the fiscal year ended September 30, 2019, the Company recorded approximately $453,000 in additional revenue from the WNA for weather that was approximately 4% warmer than normal.

For the fiscal years ended September 30, 2018 and 2017, the Company recorded $45,000 and $1,839,000 in additional revenue from the WNA for weather that was approximately 1% and 18% warmer than normal, respectively.

Any billings or refunds related to the WNA are completed following each WNA year end, which runs from April to March.

The Company recorded approximately $1,193,000 and $453,000 in additional revenue from the WNA for weather that was approximately 8% and 4% warmer than normal for the fiscal years ended September 30, 2020 and 2019, respectively.

As normal weather is based on the most recent 30-year temperature average, the number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed.

As a result of adding recent warmer than normal years to replace colder historical years to the 30-year period, the number of heating degree days that defines normal has declined from 3,998 in fiscal 2013 to 3,925 in fiscal 2019.

The Company's prior rates were designed on 4,000 heating degree days based on its last non-gas rate filing;

however, the 2019 WNA model is recovering based on 3,949 heating degree days, or about 1% less than what the prior non-gas rates were designed to recover.

The 30-year normal has been reset to 3,959 in the determination of the new non-gas base rates in the current rate application.

As a result of adding recent warmer than normal years to replace historical colder years, the number of heating degree days that defines normal has declined from 3,998 in fiscal 2013 to 3,914 when incorporating fiscal 2020 heating degree days.

The Company also has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory.

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The combination of a 12% reduction in the average cost of gas in storage during fiscal 2020 and a 6% reduction in the ICC factor, resulted in a decline in ICC revenues of approximately $74,000 from fiscal 2019.

This compares to a decline of $35,000 in ICC revenues for fiscal 2018 compared to fiscal 2017.

Based on current storage balances and natural gas futures, the average dollar balance of gas in storage should remain stable and, with a more consistent ICC factor, should result in less volatility in ICC revenues.

Based on current storage balances and natural gas futures prices, the average dollar balance of gas in storage in fiscal 2021 should be similar to 2020, which, in combination with a stable ICC factor due to the current low interest rate environment, should result in similar ICC revenues.

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers.

The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company.

The cost of natural gas is a pass-through cost and is independent of the non-gas rates of the Company.

This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations.

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At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization.

Currently, the local economy continues to show modest growth and should continue to improve absent a major economic setback on a local, regional or national level.

Roanoke Gas is required to submit an Annual Information Filing ("AIF") each year to the SCC.

Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets.

If the results of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery accelerated to the point where the actual return for the period adjusts to the mid-point of the range.

The Company's earnings test is required for its fiscal year ended September 30, 2020 and must be filed with the SCC by January 2021.

As Roanoke Gas' fiscal 2020 earnings exceed the mid-point, the Company accelerated recovery of $525,000 in ESAC assets.

Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which is primarily associated with the utility segment.

Additional segment analysis is provided in areas where the investment in affiliates segment (investment in MVP and Southgate) represent a significant component of the expense comparison.

Fiscal Year 2019 Compared with Fiscal Year 2018

The table below reflects operating revenues, volume activity and heating degree days.

Operating Revenues

Year Ended September 30,

Increase / (Decrease)

Gas Utilities

Total Operating Revenues

Delivered Volumes

Year Ended September 30,

Increase / (Decrease)

Regulated Natural Gas (DTH)

Residential and Commercial

Transportation and Interruptible

Total Delivered Volumes

Heating Degree Days (Unofficial)

Total gas utility operating revenues for the year ended September 30, 2019 increased by 5% from the year ended September 30, 2018 primarily due to the implementation of higher non-gas rates and slightly higher gas costs.

The Company implemented new non-gas base rates effective for natural gas service rendered on or after January 1, 2019, subject to refund.

The revenues have been reduced by management's estimate of a rate refund pending final resolution of the rate application and order by the SCC.

Total natural gas deliveries decreased by less than 1% from last year primarily due to warmer weather, offset by increased industrial consumption.

Industrial consumption, as reflected in the transportation and interruptible volumes, increased due to a significant increase in usage by one customer and a large commercial customer that transferred to firm transportation during fiscal 2019.

Residential and commercial customers' natural gas usage tends to be more weather sensitive as reflected by a 3% decline in volumes on 4% fewer heating degree days.

After adjusting for WNA and the transfer of the large commercial customer to firm transportation, total residential and commercial volumes reflect an increase of more than 1%.

The average commodity price of natural gas delivered during fiscal 2019 was approximately 4% per decatherm higher than for fiscal 2018.

Natural gas commodity prices spiked during December 2018 due to weather, but have since returned to lower levels.

The prior year included a reserve of $1,320,167 associated with the accumulated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate.

The current fiscal year includes a reserve of $523,881 as the accrual for excess revenues ended with the implementation of new non-gas rates, which incorporated the reduction in the federal income tax rate.

Other revenues decreased by 40% due to a significant reduction in services during the last half of the year.

Additional segment analysis is provided in areas where the investment in affiliates segment (investment in MVP and Southgate) represent a significant component of the comparison.

The Company's operations are affected by the cost of natural gas, as reflected in the consolidated income statement under the line item cost of gas - utility.

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Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance.

The term gross utility margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Therefore, the following discussion of financial performance will reference gross utility margin as part of the analysis of the results of operations.

Gross Utility Margin

Year Ended September 30,

Utility revenues

Gross Utility Margin

Gross utility margins increased over last year primarily as a result of implementing higher non-gas base rates effective January 1, 2019.

SAVE Plan revenues declined by nearly $2,900,000 as all related SAVE investment through December 31, 2018 was incorporated into the new non-gas base rates.

As noted above, the SCC staff recommended a change in the proposed rate design of the non-gas rate increase between customer base charge and volumetric rates.

In designing the rates submitted in the rate application, the Company included SAVE related revenues in the base charge component as the SAVE rider was previously reflected as a fixed fee on customers bills.

As a result, the new rates implemented in January 2019 included a much larger allocation of the rate increase to the customer base charge.

The SCC staff recommended in their report to significantly reduce the customer base charge rate and move it to the volumetric component of non-gas rates.

Due to the staff's position and the results of non-gas rate applications from other Virginia utilities, the Company incorporated into its rate refund assumptions a significant reduction in customer base charge revenue and an increase in volumetric revenue.

As a result, the net impact of the rate increase incorporating the rate refund assumptions resulted in an increase in the customer base charge of $1,009,479 and an increase in the volumetric margin of $3,409,095.

As noted above, WNA revenues were higher due to warmer weather, while excess revenues related to tax reform were lower during the current year as new non-gas rates were implemented that incorporated the effects of the TCJA.

The changes in the components of the gross utility margin are summarized below:

Years Ended September 30,

Increase / (Decrease)

Customer Base Charge

Carrying Cost

Excess Revenues - Tax Reform

Other Revenues

Operations and Maintenance Expense - Operations and maintenance expense increase d by $1,617,591 , or 13%, from last year primarily due to higher compensation costs, amortization of regulatory assets, corporate insurance costs, lower capitalized overheads, maintenance activities and higher bad debt expense.

Total compensation costs increased by $647,000 due to higher staffing levels in regulatory and operations support combined with wage increases.

Beginning in January 2019, concurrent with the implementation of new non-gas rates, the Company began amortizing certain regulatory assets for which recovery was included in the rate application.

A total of $372,000 was charged to expense related to the amortization of these assets.

Most of the regulatory assets have a 5-year amortization period.

Corporate insurance expense increased by $125,000 due to higher premiums related to increased liability limits and higher deductible reserves.

Capitalized overheads declined by $255,000 due to lower overall capital expenditures and reduced LNG production related to timing of facility upgrades at the plant.

Contracted maintenance related to work on the LNG plant and brush clearing along the Company's transmission right of way increased maintenance costs by $186,000.

Bad debt expense increased by $55,000 associated with increased customer billings.

General Taxes - General taxes increased $188,784 , or 10% , primarily due to higher property taxes associated with increases in utility property and higher payroll taxes.

Depreciation - Depreciation expense increased by $497,930 , or 7% , corresponding to a 6% increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $2,081,817 due to AFUDC related to increased investment in the project.

Total cash investment in fiscal 2019 was nearly $21 million.

The investment in Mountain Valley Pipeline and the related AFUDC earnings are discussed further under the Equity Investment in Mountain Valley Pipeline section below.

Other Income (Expense), net - Other income increased by $107,014 primarily due to a full year of revenue sharing received by the Company under the gas supply asset management agreement and the adoption of ASU 2017-07.

Revenue sharing fees increased by $313,000 as the incentive mechanism was only in effect for a portion of last year.

ASU 2017-07 requires that net periodic benefit costs, other than service cost, be presented outside of income from operations.

As a result of the adoption of this ASU, the prior years financial statements have been adjusted retrospectively with the reclassification of $123,000 in net expense reduction from operations and maintenance to other income for fiscal 2018.

Current year net expense reductions related to other benefit costs were less than $2,000.

The remaining difference is attributable to pipeline assessments and charitable contributions.

See the Regulatory and Tax Reform section below for more information on revenue sharing and Note 1 for information on the adoption of ASU 2017-07.

Interest Expense - Total interest expense increased by $1,156,986 , or 47% , due to a 41% increase in the average total debt outstanding during the year attributed to the investment in MVP and financing expenditures in support of Roanoke Gas' capital budget.

The Company contributed nearly $21 million to its investment in MVP during the year as Midstream's borrowing increased by more than $22 million with a corresponding increase in interest expense of $832,000.

Roanoke Gas' total borrowing increased by more than $10 million related to the issuance of an unsecured note to refinance a portion of the line-of-credit, which accounted for the remaining increase in interest expense.

The average interest rate on consolidated borrowings increased during the current year from 3.80% to 3.92%.

Income Taxes - Income tax expense decreased by $244,405 , or 8% , even though pre-tax earnings increased.

The effective tax rate was 23.4% for fiscal 2019 compared to 28.4% for fiscal 2018 .

These decreases in the effective tax rate and income tax expense correspond to the reduction in the corporate federal income tax rate from the 24.3% blended federal tax rate in fiscal 2018 to the 21% statutory rate in fiscal 2019.

Fiscal 2018 income tax expense also included $256,444 of additional tax expense for the revaluation of net deferred tax assets of the unregulated operations to the 21% federal tax rate.

Income tax expense related to the MVP investment increased by $359,000 due to the significant growth in pre-tax earnings.

Additional information regarding the impact of tax reform can be found in Note 8 and under the Regulatory and Tax Reform section below.

Net Income and Dividends - Net income for fiscal 2019 was $8,698,412 compared to $7,297,205 for fiscal 2018 .

Basic and diluted earnings per share were $1.08 in fiscal 2019 compared to $0.95 in fiscal 2018 .

Dividends declared per share of common stock were $0.66 in fiscal 2019 compared to $0.62 in fiscal 2018 .

The term gross utility margin is not intended to represent or replace operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

The following results of operations analyses will reference gross utility margin.

Fiscal Year 2020 Compared with Fiscal Year 2019

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Operating Revenues

Year Ended September 30,

Year Ended September 30, 2020 2019 Decrease Percentage

Gas Utilities $ 62,408,925 $ 67,306,260 $ (4,897,335) (7) %

Other 666,466 720,265 (53,799) (7) %

Total Operating Revenues $ 63,075,391 $ 68,026,525 $ (4,951,134) (7) %

Delivered Volumes

Year Ended September 30,

Year Ended September 30, 2020 2019 Increase / (Decrease) Percentage

Regulated Natural Gas (DTH)

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Heating Degree Days (Unofficial) 3,623 3,791 (168) (4) %

Total gas utility operating revenues for the year ended September 30, 2018 increased by 5% from the year ended September 30, 2017 primarily due to higher gas sales and increased SAVE Plan revenues more than offsetting refunds related to the reduction in the corporate federal income tax rate and lower gas costs.

Total natural gas deliveries increased by 16% over fiscal 2017 primarily due to weather and increased commercial and industrial consumption.

Industrial consumption, as reflected in the transportation and interruptible volumes, increased as net production activities increased due to a stronger local economy.

Residential and commercial volumes increased by 22% on a corresponding 22% increase in heating degree days.

Usage by larger commercial customers, which generally are less weather sensitive than residential and smaller commercial customers, increased by 20% due to a combination of colder weather, new business development in the region and increased usage by existing customers.

SAVE Plan revenues grew by 17% due to the Company's ongoing investment in its SAVE related infrastructure replacement program.

The Company also recorded a reserve in the amount of $1,320,167 associated with the accumulated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate.

Other revenues increased by 14% due to increased customer requirements.

Total gas utility operating revenues for the year ended September 30, 2020 decreased by 7% from the year ended September 30, 2019 primarily due to a reduction in residential and commercial volumes, lower natural gas commodity prices and reduced SAVE Plan revenue more than offsetting a full year impact of the non-gas rate increase and higher transportation volumes.

The primarily weather sensitive residential and commercial natural gas deliveries declined by 7%, corresponding to a 4% decline in heating degree days during the period, while transportation volumes increased by 32%.

After adjusting for WNA, residential volumes declined by more than 2% and commercial volumes fell by more than 6%.

These WNA adjusted lower volumes reflect the impact of COVID-19 on local businesses and other entities through closings and reduced operations.

The significant increase in transportation and interruptible volumes is attributable to a single multi-fuel use industrial customer that switched its primary fuel source to natural gas due to favorable natural gas commodity price levels;

however, this customer's natural gas usage has since returned to prior consumption patterns.

The average commodity price of natural gas delivered declined by 29% per decatherm from the same period last year due to available supplies and higher storage levels from a mild winter.

SAVE Plan revenues declined by $327,000 as the SAVE Rider reset effective January 1, 2019, and all qualifying SAVE Plan investments through December 31, 2018 were included in rate base and used to derive the new non-gas base rates.

For the first three months of fiscal 2019, SAVE Plan revenues represented a return on a five-year accumulation of SAVE investment.

Subsequent to January 1, 2019, the SAVE Plan investments reset and currently include less than two years of qualifying investments on which to earn a return.

As discussed above, the Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund.

As a result, fiscal 2020 includes a full year of revenues under the new non-gas base rates, while the prior year revenues include only nine-months of the higher non-gas rates.

Other revenues decreased by 7% from the same period last year due to the unregulated operations contract completion.

The contract ended in August 2020 and accounted for approximately 75% of other revenues for fiscal 2020.

The Company does not currently anticipate pursuing other customers for these services.

Gross Utility Margin

Year Ended September 30,

Increase / (Decrease)

Year Ended September 30, 2020 2019 Increase / (Decrease) Percentage

Utility revenues $ 62,408,925 $ 67,306,260 $ (4,897,335) (7) %

Cost of gas 23,949,481 32,401,123 (8,451,642) (26) %

Gross Utility Margin $ 38,459,444 $ 34,905,137 $ 3,554,307 10 %

Gross utility margins were nearly unchanged from fiscal 2017, as higher SAVE Plan revenues and increased volume deliveries were offset by the excess revenue reserve adjustment to refund customers for the effects of the lower federal income tax rate.

Total SAVE Plan revenues increased by $656,000 as the Company continues to invest in qualified infrastructure projects.

Since January 2014, the Company had invested nearly $40,000,000 in such projects.

Volumetric margin increased by nearly $2,316,000 due to greater natural gas deliveries resulting from much colder weather and growth in both customers and non-weather related customer usage.

Much of the margin related to increased sales was offset by a much lower WNA adjustment.

Weather during fiscal 2018 was nearly normal while the weather in fiscal 2017 was 18% warmer than normal resulting in a reduction in the WNA adjustment of $1,795,000.

The remaining net increase in WNA adjusted margin is related to increased economic activity in the region combined with customer growth.

ICC revenues declined by $35,000 due to a lower ICC factor.

Gross utility margins increased over last year primarily as a result of implementing the non-gas base rate increase effective January 1, 2019 and higher delivered transportation and interruptible volumes.

The new non-gas rates were in effect for the entire fiscal 2020 year compared to only nine months for fiscal 2019.

As a result, customer base charge revenues increased by $927,475.

Volumetric margin increased by $1,792,553, attributable to 80% of the non-gas base rate increase being allocated to volumetric margin and the single industrial customer previously discussed, net of the effect of lower residential and commercial volumes due to warmer weather and the effects from COVID-19.

WNA margin increased by $739,823 as weather was 8% warmer than normal and more than 4% warmer than the same period last year.

In addition, the current year WNA margin reflects the pricing from a full year implementation of the higher non-gas rates in the calculation.

The prior year also included a reserve for excess revenues attributable to the reduction in the corporate federal income tax rates for the period of October 1, 2018 through December 31, 2018 prior to the implementation of the new non-gas rates.

These excess revenues were subsequently refunded to customers in calendar 2019.

The current fiscal year has no such adjustment as the new non-gas rates incorporated the effect of the lower federal income tax rate.

The changes in the components of the gross utility margin are summarized below:

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Customer Base Charge $ 14,413,709 $ 13,486,234 $ 927,475

SAVE Plan 1,272,070 1,599,281 (327,211)

Volumetric 21,091,007 19,298,454 1,792,553

WNA 1,192,715 452,892 739,823

Carrying Cost 388,607 462,260 (73,653)

Excess Revenues - Tax Reform — (523,881) 523,881

Other Revenues 101,336 129,897 (28,561)

Operations and Maintenance Expense - Operations and maintenance expense decreased by $102,180, or 1%, from fiscal 2017 primarily due to reductions in compensation costs, contracted services and benefit costs partially offset by the reclassification of net periodic benefit costs other than service cost from operating and maintenance expense to non-operating expense and higher bad debt expense.

Compensation declined by $127,000 in large part due to the reduction in employees related to the outsourcing of the customer service function, net of additions in other areas.

Contracted services also declined as the higher costs related to outsourcing the customer service function were offset by declines in meter reading costs, due to the implementation of an automated meter reading system in fiscal 2017, and the insourcing of the utility line locating function.

Employee benefit costs declined by $705,000 primarily as a result of decreases in the actuarially determined expenses of both the pension and other post-retirement benefit plans.

Strong asset performance and funding combined with an increase in the discount rate served to reduce the actuarially determined expenses of the plans and improve the overall funded status.

Bad debt expense increased by $85,000 on higher gross customer billings due to a much colder heating season compared to the prior year.

Operating and maintenance expense has been revised for fiscal 2018 and 2017 due to the adoption of ASU 2017-07 related to the change in financial presentation of other net periodic benefit costs.

As a result of this reclassification, operation and maintenance expense increased by $648,971, while at the same time other income (expense), net increased by the same amount.

See Note 1 for more information regarding the ASU 2017-07.

General Taxes - General taxes increased $91,940, or 5%, primarily due to higher property taxes associated with increases in utility property offset by lower payroll taxes.

Depreciation - Depreciation expense increased by $699,607 or 11%, corresponding to 10% increase in utility plant investment.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $516,885 due to the ongoing investment in the Mountain Valley Pipeline.

Other Income (Expense), net - Other income (expense) moved from $658,879 in net other expense to $224,868 in net other income primarily due to the reclassification of other net periodic benefit costs out of operation and maintenance expense into other income (expense) as required under ASU 2017-07.

The reclassification accounted for $648,971 of the change with most of the remaining difference resulting from the implementation of the revenue sharing incentive mechanism, lower pipeline assessments and charitable commitments and higher interest earnings.

See Note 1 for additional information regarding ASU 2017-07.

Total $ 38,459,444 $ 34,905,137 $ 3,554,307

Operations and Maintenance Expense - Operations and maintenance expense increased by $2,091,210, or 15%, from prior year primarily due to the accelerated recovery of ESAC regulatory assets, increased bad debt expense, compensation costs and professional services.

As previously mentioned, the SCC final order on Roanoke's non-gas base rate increase directed the Company to write-down $317,000 of ESAC assets that were not subject to recovery.

In addition to the annual amortization of ESAC assets, Roanoke Gas accelerated the recovery of the remaining $525,000 balance of ESAC assets as a result of the preliminary earnings test performed by the Company.

Bad debt expense increased by $336,000 related primarily to the ramifications of COVID-19.

With the service cut-off moratorium and delinquencies, the corresponding bad debt expense has continued in an upward trend.

Additionally, as the number of COVID cases continue to increase, the negative economic impact is expected to continue resulting in the potential for higher bad debt levels next year.

See the Regulatory and Tax Reform section below for more information regarding the moratorium and ESAC assets.

Total compensation costs increased by $400,000 primarily due to vesting of officer stock awards.

Professional services increased by $323,000 due to a variety of factors including legal assistance provided in the non-gas rate application, services related to union contract negotiations, services related to employee benefit plans, network systems support and other project support activities.

General Taxes - General taxes increased $127,995, or 6%, primarily due to higher property taxes associated with a nearly 9% increase in utility property.

Depreciation - Depreciation expense increased by $436,451, or 6%, corresponding to a similar increase in depreciable utility plant.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $1,794,526 due to AFUDC related to increased investment in the project.

The total MVP cash investment in fiscal 2020 was approximately $7.8 million.

Other Income, net - Other income increased by $284,414 primarily due to the $248,000 equity portion of AFUDC income related to the two Roanoke Gas transfer stations that will interconnect with the MVP.

The Company recorded AFUDC based on activity retro-active to January 1, 2019 in accordance with the provisions included in the SCC's final rate order on the non-gas base rates as discussed in the Regulatory and Tax Reform section.

Interest Expense - Total interest expense increased by $480,607, or 13%, due to a 28% increase in the average total debt outstanding during the year.

Most of the net increase in borrowing is attributable to the investment in Mountain Valley Pipeline, which accounted for $244,000 of the increase in interest expense.

Roanoke Gas funded its capital expenditures for 2018 through the $15 million equity infusion from Resources.

The average interest rate increased during the current year from 3.56% to 3.80%.

The increase in the average interest rate is due to the issuance of the $8,000,000 unsecured notes on October 2, 2017 at a rate of 3.58% which replaced a portion of the lower-rate balance under the line-of-credit combined with the rising interest rate on the Company's variable-rate debt.

Income Taxes - Income tax expense decreased by $910,254, or 24%, even though pre-tax earnings increased.

This increase is attributed to the continued investment in MVP and financing expenditures in support of Roanoke Gas' capital budget, partially offset by a reduction in the weighted-average interest rate during the period and the capitalization of $82,000 for the interest portion of AFUDC.

Roanoke Gas' interest expense increased by $326,304 as total average debt outstanding increased by $10,200,000 associated with the debt issuance in December 2019 and an increase in the borrowings under the line-of-credit.

The average interest rate decreased slightly from 3.80% in fiscal 2019 to 3.76% in fiscal 2020.

The increase in interest expense was mitigated by the capitalization of $82,000 related to the interest portion of AFUDC as authorized by the SCC's final order on the non-gas rate increase.

Midstream's interest expense increased by $154,303 as total average debt outstanding increased by $14,400,000 associated with the its investment in MVP.

The average interest rate decreased from 3.59% in fiscal 2019 to 2.76% in the current year due to the decline in the variable interest rate on Midstream's credit facility.

Income Taxes - Income tax expense increased by $654,929, or 25%, on a 22% increase in pre-tax earnings.

The effective tax rate was 23.8% for fiscal 2020 compared to 23.4% for fiscal 2019.

This decrease in the effective tax rate and income tax expense corresponds to the reduction in the corporate federal income tax rate from 34% for fiscal 2017

to a 24.3% blended rate for fiscal 2018, and ultimately to 21% in fiscal 2019.

Income tax expense related to the MVP investment was nearly unchanged as a reduced federal income tax rate offset growth in pre-tax earnings.

The effective tax rate for both years is below the combined state and federal statutory rate of 25.74% due to the amortization of the excess deferred income taxes and the excess deductions related to the vesting of restricted stock and the exercise of stock options.

Income tax expense related to the MVP investment increased by $405,000 due to the significant growth in pre-tax earnings.

The majority of the remaining $250,000 increase in income tax expense is related to the increase in pre-tax earnings of Roanoke Gas.

Net Income and Dividends - Net income for fiscal 2020 was $10,564,534 compared to $8,698,412 for fiscal 2019.

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Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are for the funding of its continuing construction program, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends.

To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and capital raised through the issuance of common stock.

Cash and cash equivalents increased by $1,383,937 in fiscal 2019 compared to an increase of $177,771 in fiscal 2018 and a decrease of $573,612 in fiscal 2017.

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its capital projects, investment in MVP, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends.

To meet these needs, the Company primarily relies on its operating cash flows and availability under short-term and long-term credit agreements.

Cash and cash equivalents decreased by approximately $1.3 million in fiscal 2020 compared to an increase of $1.4 million in fiscal 2019.

The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary

Year Ended September 30,

Cash Flow Summary Years Ended September 30,

Net cash provided by operating activities $ 12,823,903 $ 14,697,704

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Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows.

Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels.

During the first and fourth quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash provided by operating activities was approximately $14,698,000 in fiscal 2019, $13,504,000 in fiscal 2018 and $12,981,000 in fiscal 2017.

Cash provided by operating activities increased by nearly $1.2 million over last year primarily as the net result of several items including net income, depreciation, estimated provision for rate refund, gas in storage and change in over/under collection of gas costs, offset by equity in earnings and additional pension funding.

Although net income increased by $1.4 million, most of the earnings growth derived from the non-cash $2.1 million growth in equity in earnings on the investment in MVP.

Increased depreciation contributed more than $500,000 in additional operating cash, related to the increasing investment in natural gas infrastructure.

The combination of lower commodity prices during the summer injection period and lower storage levels contributed $1.1 million in additional cash over last year.

The net rate refund estimate increased by $1.2 million due to the collection of revenues in excess of management's estimate of the final rate award related to the non-gas base rate application, net of the partial refunding of the excess tax revenues collected in rates prior to the implementation of the new non-gas rates in January 2019.

Over-collections of gas cost increased by more than $3.4 million over the same period last year.

Natural gas prices spiked in December and futures prices at the time indicated that natural gas commodity prices would remain at an elevated level during the winter months.

Based on this information, the Company filed its quarterly PGA adjustment reflecting higher prices;

however, commodity prices quickly declined to levels below the prior year during the second and third fiscal quarters resulting in the move to an over-collected position.

A $1.2 million decrease in cash resulted from the change in prepaid income taxes, as adjustments were made in the prior year to reduce estimated tax payments as a result of TCJA.

Accounts payable and accrued expenses used an additional $2.9 million due to reduction in accounts payable balances associated with lower gas costs and additional funding provided to the pension plan as reflected in Note 9.

Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels.

During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash flow from operating activities decreased by nearly $1.9 million when compared to the prior year.

The decrease in cash flow provided by operations was primarily driven by changes in regulatory assets and liabilities, partially offset by net income and changes in accounts payable.

The table below summarizes the significant operating cash flow components:

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2020 2019 Increase (Decrease)

Net Income $ 10,564,534 $ 8,698,412 $ 1,866,122

Non-cash adjustments:

Depreciation 8,126,427 7,600,852 525,575

Equity in earnings (4,814,874) (3,020,348) (1,794,526)

Gas in storage

AFUDC (330,208) — (330,208)

Allowance for doubtful accounts 592,398 7,167 585,231

ESAC assets 1,022,195 303,470 718,725

Changes in working capital and regulatory assets and liabilities:

Accounts receivable (141,482) (258,024) 116,542

Prepaid income taxes 510,357 (320,297) 830,654

Change in over-collection of gas costs

Deferred taxes

Accounts payable and accrued expenses 659,276 (2,745,377) 3,404,653

Change in over (under) collection of gas costs (1,895,555) 1,084,735 (2,980,290)

Rate refund (3,827,589) 2,507,422 (6,335,011)

WNA 1,171,342 (399,956) 1,571,298

Other 1,187,082 1,239,648 (52,566)

Net cash provided by operating activities $ 12,823,903 $ 14,697,704 $ (1,873,801)

In 2020, Roanoke Gas issued $3.8 million of refunds related to interim rates that began in fiscal 2019, resulting in a $6.3 million change in operating cash flow.

As natural gas commodity prices rapidly declined in 2020, the Company’s gas cost recovery moved from an over-collected position at the end of 2019 to an under-collected position in 2020, driving a $3.0 million decrease in operating cash flow.

These significant year-over-year decreases were offset by increases in net income, net of AFUDC earnings, and depreciation.

Fiscal 2020 also had non-cash expense for uncollectible accounts and the ESAC accelerated recovery.

Colder than normal weather for the WNA period ended September 30, 2020 resulted in a net payable versus a net receivable at September 30, 2019, driving an increase in

operating cash flows of $1.6 million.

In addition, the $3.4 million operating cash increase from accounts payable and accrued expenses is primarily attributable to changes in natural gas commodity prices year-over-year and fiscal 2019 elevated employee benefit plan funding.

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility plant projects, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and gas distribution system facilities and expansion of its natural gas system to meet the demands of customer growth, as well as the continued investment by Midstream in the MVP.

Roanoke Gas' expenditures related to its pipeline renewal program and other system and infrastructure improvements were nearly $21.9 million in fiscal 2019 compared to $23.3 million in fiscal 2018 and $20.7 million in fiscal 2017.

Roanoke Gas renewed 8.4 miles of natural gas distribution main and replaced 875 service lines to customers in fiscal 2019.

This compares to 8.3 miles of main and 496 service lines in fiscal 2018 and 9 miles of main and 459 service lines in fiscal 2017.

The current renewal program is focused on the replacement of pre-1973 first generation plastic pipe.

In addition, the Company’s capital expenditures included costs to extend natural gas distribution mains and services to 553 new customers in fiscal 2019 compared to 451 new customers in fiscal 2018 and 499 new customers in fiscal 2017.

Roanoke Gas is constructing two gate stations to access the MVP and has nearly completed the extension of the gas distribution system to connect to these stations.

These two stations will provide additional gas supply as well as provide natural gas to currently unserved areas once MVP is operational.

The LNG facility is being upgraded with the installation of two new boilers and a new natural gas generator.

The MVP interconnect projects and the LNG upgrades account for 70% of the construction work in progress as of September 30, 2019.

Fiscal 2018 projects included a major system reinforcement to increase capacity within certain areas of the Company's natural gas distribution system, the extension of gas service to a new industrial park, which included system reinforcement to the surrounding service area, and progress toward extending Roanoke Gas' distribution pipeline to interconnect with the MVP.

Depreciation covered approximately 35% of the current year's capital expenditures compared to 30% for 2018 and 31% for 2017, with the balance provided from other operating cash flows and borrowings.

Capital expenditures are expected to remain at elevated levels over the next few years.

The Company is continuing its focus on replacing the remaining pre-1973 first generation plastic pipe with modern polyethylene pipe.

This renewal project is expected to be completed by 2024.

The current capital budget for fiscal 2020 is expected to be on a level consistent with fiscal 2019 and 2018.

Under this budget, the Company plans to complete its interconnect with the MVP, finish the LNG upgrades, conduct system reinforcements and expand service to new customers.

The Company expects to increase its borrowing activity, as well as consider additional equity investment, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect Midstream's $20,965,907 fiscal 2019 funding of its participation in the LLC.

Midstream's total expected funding increased to between $53 and $55 million as discussed below, with anticipated cash investment for fiscal 2020 to be as much as $15 million.

Funding for the investment in the LLC is provided through the $26 million credit facility, which matures in 2020 and two unsecured notes in the combined amount of $24 million.

The Company is in the process of negotiating additional funding to meet the projected increase as well as an extension of the credit facility beyond 2020.

More information regarding the credit facility is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility plant, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and gas distribution system facilities and expansion of its natural gas system to meet the demands of customer growth, as well as the continued investment in the MVP.

Roanoke Gas' expenditures were approximately $22.9 million and $21.9 million in fiscal 2020 and 2019, respectively.

Roanoke Gas renewed 9.6 miles of main and 592 service lines and 8.4 miles of main and 875 service lines in fiscal years 2020 and 2019, respectively.

The current SAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe.

In addition, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 448 customers in fiscal 2020, compared to 553 customers in fiscal 2019.

Roanoke Gas is constructing two gate stations and has nearly completed the extension of the gas distribution system necessary to interconnect with the MVP.

Once MVP is operational, these two stations will provide additional natural gas supply to Roanoke Gas' existing customers as well as currently unserved areas.

Depreciation covered approximately 35% of the current and prior year's capital expenditures, with the balance provided from other operating cash flows and financing activities.

Capital expenditures are expected to remain at current levels over the next few years as Roanoke Gas continues to focus on its SAVE Plan, which is expected to be completed by 2024.

The Company expects to utilize its credit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the 2020 funding of $7.9 million for Midstream's participation in the LLC.

Midstream's total expected funding increased to between $60 and $62 million as discussed below, with anticipated cash investment for fiscal 2021 to be approximately $17 million.

Funding for the investment in the LLC is provided through the $41 million credit facility and two unsecured notes in the combined amount of $24 million.

More information regarding the credit facilities is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under debt agreements, issuance of stock and the payment of dividends.

Net cash flows provided by financing activities were $29,516,000, $20,841,000 and $9,938,000 in fiscal 2019, 2018 and 2017, respectively.

As mentioned above, the Company uses its line-of-credit to fund seasonal working capital and provide temporary financing for capital projects, which is then converted into longer-term debt or equity financing.

The increase in financing cash flows derived from Midstream's net borrowings of more than $22 million to finance its investment in MVP and the issuance of notes by Roanoke Gas.

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of stock and the payment of dividends.

Net cash flows provided by financing activities were $16.6 million and $29.5 million in fiscal 2020 and 2019, respectively.

The Company uses its line-of-credit to fund seasonal working capital needs and provide temporary financing for capital projects.

The increase in financing cash flows was derived from Midstream's net borrowings of more than $9 million to finance its investment in MVP and the $10 million issuance of notes by Roanoke Gas.

The Company also realized $1.8 million from the issuance of stock through DRIP activity and the exercise of options.

Dividend payments exceeded $5.2 million as the annualized dividend rate per share increased from $0.62 to $0.66.

In fiscal 2018, Resources issued 700,000 shares of stock through an equity offering for $15.1 million and invested the proceeds in Roanoke Gas to convert a portion of the debt financing of the capital budget provided by the line-of-credit to equity by refinancing the outstanding balance under the line-of-credit.

Cash out-flows for dividend payments exceeded $5.6 million as the annualized dividend rate increased from $0.66 to $0.70 per share.

The Company’s consolidated capitalization was 41.7% equity and 58.3% long-term debt at September 30, 2020, exclusive of unamortized debt expense.

This compares to 44.5% equity and 55.5% long-term debt at September 30, 2019.

The long-term debt as a percent of long-term capitalization increased from last year due to the debt issues listed below.

In June 2019, Midstream entered into two unsecured promissory notes and loan agreements in the total aggregate principal amount of $24,000,000.

The first note was for a 7-year term in the amount of $14,000,000 at an interest rate of 30-day LIBOR plus 115 basis points.

Midstream entered into a related swap agreement to convert the variable interest rate to a 3.24% fixed rate.

The second note was for a 5-year term in the amount of $10,000,000 at an interest rate of 30-day LIBOR plus 120 basis points.

Midstream also entered into a swap agreement on this note to convert the variable interest rate to a 3.14% fixed rate.

On June 5, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10,000,000.

These notes are scheduled to be issued on the day of closing currently proposed for December 6, 2019.

These notes will have a 10-year term from the date of issue at a fixed interest rate of 3.60%.

The proceeds from these notes will be used to finance a portion of Roanoke Gas' capital budget.

On March 28, 2019, Roanoke Gas issued notes in the aggregate principal amount of $10,000,000.

These notes have a 12-year term with a fixed interest rate of 4.41%.

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement with a two-year term expiring March 31, 2021, replacing the prior line-of-credit agreement scheduled to expire March 31, 2020.

The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance on the note.

The agreement retains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs.

The total available borrowing limits during the term of the agreement range from $3,000,000 to $30,000,000.

As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current.

On February 19, 2019, Midstream entered into an agreement with the lending institutions to amend its existing non-revolving credit agreement and related notes that provide financing for the MVP project.

The amendment increased total borrowing limits to $50 million through the date of maturity to meet the projected funding requirements for completion of the MVP.

With the exception of the increase in borrowing limits, all remaining terms under the notes remain unchanged including the variable-interest rate based on 30-day LIBOR plus 135 basis points.

Midstream used the proceeds from the two notes issued in June 2019 to pay down the balance on the notes.

As the notes were issued under a non-revolving credit agreement, the borrowing limit under this credit facility was reduced from $50 million to $26 million.

The long-term debt as a percent of long-term capitalization increased from last year due to the debt issuances described above compared to retained earnings increases, net of dividend payments.

On March 26, 2020, Roanoke Gas renewed its unsecured line-of-credit agreement, which was scheduled to expire March 31, 2021.

The new agreement is for a two-year term expiring March 31, 2022 with a maximum borrowing limit of $28,000,000.

Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period.

The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits aligned with the Company's seasonal borrowing demand.

The Company's total available borrowing limits range from $3,000,000 to $28,000,000.

On December 23, 2019, Midstream entered into the Third Amendment to Credit Agreement ("Amendment") and amendments to the related Promissory Notes ("Notes") with the corresponding banks.

The Amendment modified the original Credit Agreement and prior amendments between Midstream and the banks by increasing the total borrowing capacity to $41,000,000 from its previous $26,000,000 limit and extending the maturity date to December 29, 2022.

The Amendment retained all of the other provisions contained in the previous credit agreements and amendments

including the interest rate on the notes based on a 30-day LIBOR plus 1.35%.

The additional limits under the Amendment provide additional financing for the investment in the MVP.

On December 6, 2019, Roanoke Gas entered into unsecured notes in the aggregate principal amount of $10,000,000.

These notes have a 10-year term from the date of issue at a fixed interest rate of 3.60%.

The proceeds from these notes provided financing for Roanoke Gas' capital budget.

On December 6, 2019, Roanoke Gas amended its existing private shelf facility agreement.

This "Second Amendment" pre-authorized the Company to issue notes up to an additional $40,000,000, in aggregate, while also extending the term 3-years.

At this time, no funds have been drawn since the amendment.

On September 30, 2020, Roanoke Gas entered into a second private shelf facility agreement for the pre-authorization to issue notes up to $70 million, in aggregate, during the 5-year term of the agreement.

No funds have been drawn under the shelf agreement at this time.

At the Company's annual meeting, held on February 3, 2020, Resources shareholders approved an amendment to the Articles of Incorporation that increased the total number of authorized common shares from 10 million to 20 million.

The amendment became effective on February 4, 2020.

On February 14, 2020, Resources filed a prospectus with the SEC utilizing a shelf registration process where the Company may sell shares of common stock, in one or more offerings, of an aggregate amount up to $40,000,000.

The prospectus was filed including a supplement allowing the Company to offer a portion of these shares, up to an aggregate of $15,000,000, utilizing the at the market ("ATM") approach as defined in Rule 415 under the Securities Act.

The ATM approach allows Resources flexibility in the frequency, timing and amount of share offerings in supplementing its capital funding needs.

As of September 30, 2020, no shares had been issued through the ATM.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii).

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business.

As of September 30, 2019, the estimated recorded and unrecorded obligations are as follows:

Recorded contractual obligations:

Less than 1 year

After 5 Years

Long-Term Debt - Notes Payable (1)

Long-Term Debt - Line of Credit (2)

(1) See Note 7 to the consolidated financial statements.

(2) See Notes 6 and 7 to the consolidated financial statements.

New line-of-credit agreement executed for a 2-year term, expiring March 31, 2021.

Amounts drawn against agreement are considered non-current as they are not subject to repayment within 12-months.

Unrecorded contractual obligations, not reflected in consolidated balance sheets in accordance with US GAAP:

Less than 1 year

After 5 Years

Pipeline and Storage Capacity (3)

Gas Supply (4)

Interest on Line-of-Credit (5)

Interest on Notes Payable (6)

Pension Plan Funding (7)

Investment in MVP (8)

Franchise Agreements (9)

Other Obligations (10)

(3) Recoverable through the PGA process.

(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase.

Unable to estimate related payment obligation until time of purchase.

See Note 12 to the consolidated financial statements.

(5) Accrued interest on line-of-credit balance at September 30, 2019, including minimum facility fee on unused line-of-credit.

See Note 6 to the consolidated financial statements.

(6) Calculated interest payments notes payable included in Note 7 to the consolidated financial statements.

(7) Estimated minimum funding requirement assuming application of credit balances in plan to offset funding.

Minimum funding requirements beyond five years is not available.

See Note 9 to the consolidated financial statements for the planned funding in fiscal 2019.

(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.

(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements.

See Note 12 to the consolidated financial statements.

(10) Various lease, maintenance, equipment and service contracts.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, Midstream entered into an agreement to become a 1% member in the LLC.

The purpose of the LLC is to construct and operate the Mountain Valley Pipeline, a natural gas pipeline connecting the Equitrans gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia.

The purpose of the LLC is to construct and operate the MVP.

On November 19, 2019, the Company's Board of Directors approved a pro-rata increase in its participation in MVP.

As a result, based on the midpoint of the targeted total project cost for the MVP discussed below, Midstream's equity interest will increase to approximately 1.03% by the pipeline’s in-service date and the Company’s total estimated cash investment is expected to range from $60 to $62 million.

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia.

In addition to the Midstream's potential returns from its investment in the LLC, Roanoke Gas will benefit from another delivery source of natural gas into its distribution system.

Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility.

Damage to or interruption of supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers.

A third pipeline will reduce the impact from such an event.

In addition, the current pipeline path provides the Company with a more economically feasible opportunity to provide natural gas service to currently unserved areas within the Company's certificated service territory.

On October 13, 2017, FERC issued the CPCN for the MVP.

In January 2018, FERC began issuing Notices to Proceed, which granted the LLC permission to begin construction activities as the LLC also had received the necessary federal permits and the required Virginia and West Virginia environmental agency permits specified by FERC.

Since construction began on the pipeline, the LLC has encountered various challenges, including pipeline protesters, legal challenges to various federal and state permits resulting in stop orders and FERC intervention.

In July 2018, the Fourth Circuit rescinded permits allowing the pipeline to cross a 3.6 mile section of the Jefferson National Forest.

In October 2018, the same court vacated the West Virginia water crossing permits with the Army Corp of Engineers subsequently pulling the related Virginia permits.

In October 2019, FERC issued a project-wide order halting forward-construction progress in response to the October 11, 2019, order by the Fourth Circuit granting a stay of MVP's Biological Opinion and Incidental Take Statement issued by the U.S.

Fish and Wildlife Service in November 2017.

The FERC order directed activity on the pipeline to be focused on restoration and stabilization activities to protect the environment along the pipeline.

The LLC is currently working with all regulatory entities and the Fourth Circuit to resolve these issues and the managing partner anticipates the reinstatement of these permits and authorization.

As a result of the most recent action by FERC, the managing partner of the LLC has revised the timeline for completing the MVP.

The full in-service date for the pipeline to be operational is now targeted for late 2020.

Although the total MVP project is approximately 90% completed, additional time is needed to resolve the issues above for the remaining construction to be completed.

Furthermore, these delays have resulted in a revised estimate for the total project cost of between $5.3 and $5.5 billion, of which Midstream's portion is expected to be between $53 million and $55 million.

The additional delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action, which could provide for the recovery of these higher costs.

With the recently revised extended time line and higher projected costs, Midstream will need additional funding to fulfill its obligation.

The Company is in the process of negotiating with Midstream's existing debt holders for additional funding and an extension of the credit facility beyond 2020.

See Note 15 regarding an increase in the Company's participation in MVP and corresponding $1.6 million expected funding increase in its investment.

The current earnings from the investment in MVP relates to the AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately construction phases of the pipeline.

AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project.

The level of investment in MVP, as well as the AFUDC, will continue to grow as construction activities continue.

When the pipeline is completed and placed into service, AFUDC will cease.

Once operational, earnings will be derived from capacity charges for utilizing the pipeline.

On April 11, 2018, the LLC announced the MVP Southgate project, which is a planned 70 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina.

Midstream will be a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project.

On November 6, 2018, the LLC filed with FERC the formal application request to construct the Southgate pipeline.

Unlike with its investment in the MVP, where the Company was an important member of the project and where the pipeline would benefit Roanoke Gas by providing additional natural gas access to its distribution system, Midstream's participation in the Southgate project is for investment purposes only.

The targeted in-service date for Southgate is the end of calendar 2020.

Any further delays in the completion of the MVP will extend the completion date of Southgate.

In addition to Midstream's potential returns from its investment in the LLC, Roanoke Gas will benefit from this additional delivery source.

Currently, Roanoke Gas is served by two pipelines and an LNG peak-shaving facility.

Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers.

This additional capacity would reduce the impact from such an event as well as allow the Company to better meet both current and future demands for natural gas.

In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to currently unserved areas within its certificated service territory.

Total MVP project work is approximately 92% complete.

Activity on the MVP was limited for most of fiscal 2020 due to legal and regulatory challenges to the project, including the October 2019 FERC issued project-wide order halting forward-construction progress.

On October 9, 2020 the FERC partially lifted this order, allowing some upland construction to resume.

Although certain permits and authorizations for the MVP project were received in the fourth quarter of fiscal 2020, there remain pending legal and regulatory challenges and authorization requests to, or otherwise affecting, certain aspects of the project and certain of such permits and authorizations, which the LLC is working to resolve.

As of November 3, 2020, based primarily on unanticipated delays during the prime summer and fall 2020 construction seasons resulting from the LLC’s inability to complete MVP project work under Nationwide Permit 12 authority (which was received in September 2020 and subsequently temporarily stayed in October 2020 by the Fourth Circuit Court of Appeals and then further stayed by the Fourth Circuit Court on November 9, 2020) and the continued need for

authorization from the FERC to complete construction work on approximately 25 miles of the project route, the full in-service date for the MVP project has been extended to the second half of calendar 2021 at a total project cost of $5.8 billion to $6.0 billion, excluding AFUDC.

Completion of the project in accordance with the targeted full in-service date and cost will require, among other things, timely authorization by the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order, timely reinstatement of the LLC’s Nationwide Permit 12 permits or utilization of alternative permitting authority and/or construction methods to cross streams and wetlands in a manner not requiring a Nationwide Permit 12, as well as resolution of challenges to the Biological Opinion and Incidental Take Statement issued by the U.S.

Fish and Wildlife Service for the MVP project and receipt of authorizations from the Bureau of Land Management and U.S.

Forest Service.

Due to the uncertainty regarding the timing of permitting and the outcome of any legal challenges, on August 25, 2020, the LLC filed a request with the FERC for an extension of time to complete the MVP project for an additional two years through October 13, 2022.

On October 9, 2020, the FERC granted this request.

In December 2019, Midstream entered into the Third Amendment to Credit Agreement and amended the corresponding associated notes to increase the borrowing capacity under the credit facility from $26 million to $41 million and extend the maturity date to December 29, 2022.

The amended agreement and notes will provide additional financing capacity for MVP funding;

however, due to the ongoing delays, additional financing may be required.

If the legal and regulatory challenges are not resolved and/or restrictions are imposed by the government related to COVID-19 that impact future construction, the cost of the MVP and Midstream's capital contributions may increase above current estimates, resulting in additional financing requirements, and a delayed in-service date.

The current earnings from the MVP investment are attributable to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and construction of the pipeline.

AFUDC is an accounting method whereby the costs of debt and equity funds used to finance infrastructure construction are credited to income and charged to the cost of the project.

The level of investment in MVP, as well as the AFUDC, will grow as construction activities continue.

However, when the pipeline, or a portion of the pipeline, is completed and approved by FERC to be placed into service, recognition of AFUDC income will be reduced proportionally or cease.

Once in service, earnings will be derived from cash flows for pipeline utilization capacity charges, per contract.

It is expected that Midstream's future earnings will be less than the current level of AFUDC recognized.

In 2018, Midstream became a participant in Southgate, a project to construct a 75-mile pipeline extending from the MVP mainline at the Transco interconnect in Virginia to delivery points in North Carolina.

Midstream is a less than 1% investor in the Southgate project and, based on current estimates, will invest approximately $2.1 million in Southgate.

Midstream's participation in the Southgate project is for investment purposes only.

The FERC issued the CPCN for Southgate in June 2020;

however, the FERC, while authorizing the project, directed the Office of Energy Projects to not issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop work order and authorizes the LLC to continue constructing the MVP project.

On August 11, 2020, North Carolina regulators denied the Southgate project's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding the completion of the MVP project, which denial was appealed by the LLC on September 10, 2020.

The Southgate project is targeted to be placed in-service in 2022, depending upon, among other things, favorable and timely resolution of the foregoing and other regulatory decisions and processes.

Regulatory and Tax Reform

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates of approximately $10.5 million.

This application incorporated into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets and SAVE plan investments and related costs previously recovered through the SAVE rider.

On October 10, 2018, Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates.

This application incorporated into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets, including all ESAC related costs, and SAVE plan investments and related costs previously recovered through the SAVE rider.

Approximately $4.7 million of the rate increase request was attributable to moving the SAVE Plan related revenues into non-gas base rates.

The new non-gas base rates were placed into effect for gas service rendered on or after January 1, 2019, subject to refund, pending audit by SCC staff, hearing and final order by the SCC.

On June 28, 2019, the SCC staff issued their report and recommendations related to the rate application.

The SCC staff report included a recommendation for a non-gas rate increase of approximately $6.5 million.

Management reviewed the SCC staff report and submitted rebuttal testimony to certain proposed adjustments included in the report.

At the hearing held on August 14 and 15, the Company addressed specific differences with SCC staff, including the proposed return on equity, the exclusion of certain infrastructure items from rate base, changes in customer class rate design and the exclusion of a portion of the regulatory assets associated with the ESAC costs.

The hearing examiner's report is not expected until December 2019, with a final order expected from the SCC in early 2020.

Based on its assessment of the

SCC staff report and the rebuttal testimony and evidence presented at the hearing, management has established a provision for a refund of revenues collected in excess of management's expectations regarding the final rate award.

On November 19, 2019, the hearing examiner issued his report, which was subsequently revised on November 26, 2019.

Although the revised report indicated a more favorable result than reflected in management's estimates, no adjustment was made to the rate refund estimate included in the September 30, 2019 financial statements, as recent rate orders from the SCC Commissioners have differed from the findings included in the hearing examiners' reports.

The Company will continue to monitor information and refine its assumptions regarding its refund estimates until such time as the SCC issues its final order and new billing rates are finalized.

Since its prior rate case in 2013, Roanoke Gas has deferred costs attributable to compliance and safety related expenses.

These ESAC expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five-year period.

As noted above, the SCC staff report recommended excluding a portion of these costs from rate recovery.

The Company has evaluated the situation and adjusted the valuation based on its assessment of the resolution.

If the ultimate result is different from management's assessment, any difference would be further adjusted following a final order from the SCC.

As noted above, the general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%.

Following the completion of the SCC staff audit and the issuance of the hearing examiner's report, the SCC issued its final order on January 24, 2020.

The SCC order awarded Roanoke Gas an annualized non-gas rate increase of $7.25 million with approximately 80% of the increase allocated to the volumetric component of rates.

The non-gas rate award provided for a 9.44% return on equity but excluded from rates, at the current time, a return on the investment of two interconnect stations with the MVP.

In addition, the final order directed the Company to write-off a portion of ESAC assets that were excluded from recovery under the rate award.

As a result, in the first quarter the Company expensed an

additional $317,000 of ESAC assets above the annual amortization amount.

Rates authorized by the SCC's final order required the Company to issue customers $3.8 million in rate refunds, which the Company completed in March 2020.

As noted above, the SCC order excluded a return on investment of the two interconnect stations currently under construction that will connect the MVP pipeline into the Company's distribution system;

however, the order did provide for the ability to defer financing costs of these investments for future recovery.

After conferring with SCC staff regarding proper treatment, the Company began recognizing AFUDC to capitalize both the equity and debt financing costs incurred during the construction phases retroactive to January 1, 2019, the rate award's effective date.

For the fiscal year ended September 30, 2020, the Company included a total of $330,000 in AFUDC income, with $248,000 reflected in other income, net and $82,000 as an offset to interest expense.

On March 16, 2020, in response to COVID-19, the SCC issued an order applicable to all utilities operating in Virginia to suspend disconnection of service to all customers until May 15, 2020.

The Commission extended the moratorium on disconnections through October 5, 2020.

These moratorium orders prohibited utilities from disconnecting any customer for non-payment of their natural gas service and from assessing late payment fees.

Subsequently, during the 2020 special session of the Virginia General Assembly, HB5005 was enacted and extended the moratorium for residential customers until the Governor determines that the economic and public health conditions have improved such that the prohibition does not need to be in place, or until at least 60 days after such declared state of emergency ends, whichever is sooner.

Therefore, residential customers that would normally be disconnected for non-payment will continue incurring costs for gas service during the moratorium, resulting in higher potential write-offs.

The Company has increased its provision for bad debts for fiscal 2020;

however, the potential magnitude of the combined impact from the economy and the moratorium on bad debts continues to be uncertain.

The Company supported the decision to suspend service disconnections in light of the current economic situation and continues to work with its customers in making arrangements to keep or bring their accounts current.

In April 2020, the SCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date.

Formal guidance has not been provided by the SCC at this time.

The Company did not defer any costs in 2020 due to the results of its earnings test, described below.

In addition, HB5005 provides The Coronavirus Aid, Relief, and Economic Security (CARES) Act's funds to assist customers with past due balances.

The amount of funding and the potential impact on bad debt reserves is currently unknown at this time;

however, management continues to evaluate the potential application of the order and possible funding relief on the consolidated financial statements.

Roanoke Gas is required to submit an AIF each year to the SCC.

Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets.

The Company's earnings test is required for its fiscal year ended September 30, 2020 and must be filed with the SCC by January 2021.

As Roanoke Gas' fiscal 2020 earnings exceed the mid-point, the Company accelerated recovery of $525,000 in ESAC assets.

The general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%.

Roanoke Gas recorded two regulatory liabilities to account for this change in the federal tax rate.

The first regulatory liability relates to the excess deferred taxes associated with the regulated operations of Roanoke Gas.

The first regulatory liability related to the excess deferred taxes associated with the regulated operations of Roanoke Gas.

As Roanoke Gas had a net deferred tax liability, the reduction in the federal tax rate required the revaluation of these excess deferred income taxes to the 21% rate at which the deferred taxes are expected to reverse.

The excess net deferred tax liability for Roanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company was recognized in income tax expense in the first quarter of fiscal 2018.

The excess net deferred tax liability for Roanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company were flowed into income tax expense in the first quarter of fiscal 2018.

A majority of the regulatory liability for excess deferred taxes was attributable to accelerated tax depreciation related to utility property.

In order to comply with the IRS normalization rules, these excess deferred income taxes must be refunded to customers and flowed through income tax expense based on the average remaining life of the corresponding assets, which approximates 28 years.

The current and non-current portions are reflected in regulatory liabilities and detailed in Note 1.

In order to comply with the IRS normalization rules, these excess deferred income taxes must be flowed back to customers and through tax expense based on the average remaining life of the corresponding assets, which approximates 28 years.

The remaining excess deferred taxes not associated with utility property are being collected from customers over a 5-year period.

The corresponding balances related to the net excess deferred taxes are included in the regulatory liability schedule in Note 1 of the consolidated financial statements.

The second regulatory liability relates to the excess revenues collected from customers.

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As a result, the Company over-recovered from its customers the difference between the federal tax rate at 34% and the 24.3% blended rate in fiscal 2018 and 21% in fiscal 2019.

To comply with an SCC directive issued in January 2018, Roanoke Gas recorded a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019.

Beginning with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess revenues to customers over a 12-month period.

The estimated refund amounts for both the excess deferred taxes and the excess revenues associated with the reduction in the federal income tax rate were subject to review and adjustment by the SCC, which was done by its staff in connection with its audit of the rate case application.

The SCC staff report agreed with the refund amounts reflected in the Company's financial statements, and, assuming no changes as a result of the hearing examiner's report or by the Commissioners, these amounts will be reflected in the final order.

To comply with an SCC directive issued in January 2018,

Roanoke Gas accrued a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019.

Starting with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess revenues to customers over a 12-month period.

The refund of the excess revenues was completed in December 2019.

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan.

The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates.

Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated the Plan each year to incorporate various qualifying projects.

In May 2019, the Company filed its most recent SAVE Plan and Rider, which continues the focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of a natural gas transfer station as well as extending the SAVE Plan to September 30, 2024.

In September 2019, the SCC approved the updated SAVE Plan and Rider effective with the October 2019 billing cycle.

The new SAVE Rider is designed to collect approximately $1.1 million in annual revenues, an increase from the approximate $500,000 in annual revenues under the prior SAVE rates.

With the inclusion of all previous SAVE investments through December 31, 2018 into the base non-gas rate application, the current SAVE Rider reflects only the recovery of qualifying SAVE Plan investments made since January 2019.

In addition, the SAVE application includes a refund factor to return approximately $543,000 in SAVE revenue over-collections from 2018, primarily resulting from the effect of the reduction in the federal income tax rate.

As noted above, Roanoke Gas contracts with a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries.

In return for the right to utilize the excess capacities of the

transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee.

In June 2018, the SCC issued an order, retroactive to April 1, 2018, approving implementation of an incentive mechanism, whereby the Company shares the utilization fee with its customers.

Under the incentive mechanism beginning April 1 each year, customers receive the initial $700,000 of the utilization fee collected through reduced gas costs, and thereafter, every additional dollar received during the annual period is split 25% to the Company and 75% to its customers.

Being in effect for the entire 2019 fiscal year, revenue sharing revenues increased by $313,000 over fiscal 2018.

On February 7, 2019, the SCC issued a final order granting a CPCN to furnish gas service to all of Franklin County, Virginia.

If the Company does not furnish gas service to the designated area within five years of the date of the order, the CPCN granting authority to serve Franklin County will be terminated.

All other CPCNs held by the Company are for territories currently served by Roanoke Gas and are intended for perpetual duration.

On August 8, 2019, the SCC issued an order granting Roanoke Gas' authority to issue up to $40 million in short-term debt and up to $100 million of long-term debt and/or common equity.

This order replaces the prior financing authorization that expired on September 30, 2019.

The new authorization request is for 5 years ending on September 30, 2024 and will allow Roanoke Gas to continue to finance its infrastructure replacement program and system growth.

The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses including a return on qualifying capital investment without the filing of a non-gas base rate application.

Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated its SAVE Plan each year to incorporate various qualifying projects.

In May 2020, the Company filed its most recent SAVE application with the SCC to further amend its SAVE Plan and for approval of a SAVE Rider for the period October 2020 through September 2021.

In its application, the Company requested to continue to recover the costs of the replacement of pre-1973 plastic pipe.

In addition, the Company requested to include the replacement of certain regulator stations and pre-1971 coated steel pipe as qualifying SAVE projects.

In September 2020, the SCC issued its order approving the updated SAVE Plan and Rider effective with the October 2020 billing cycle.

The new SAVE Rider is designed to collect approximately $2.3 million in annual revenues, an increase from the approximate $1.2 million in annual revenues under the prior SAVE rates.

In addition, the approved SAVE Plan includes a refund factor to return approximately $73,000 in SAVE revenue over-collections from 2019.

Roanoke Gas' provision for depreciation is computed principally based on composite rates determined by depreciation studies.

These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas at least every five years.

The previous depreciation study was completed and implemented in fiscal 2014.

On June 11, 2019, Roanoke Gas submitted its current depreciation study, which incorporates all of the new and replacement infrastructure and equipment placed in service since the last study.

In September 2019, the SCC administratively approved the depreciation study and directed the Company to implement the new rates retroactive to October 1, 2018.

The new depreciation rates resulted in a reduction of total depreciation expense of $32,570 for fiscal 2019.

On June 11, 2019, Roanoke Gas filed its current depreciation study, which incorporated all of the new and replacement infrastructure and equipment placed in service since the last study.

In September 2019, the SCC administratively approved the depreciation study, which resulted in a very small net reduction in the overall weighted-average composite rate from 3.32% in fiscal 2018 to 3.31% in fiscal 2019 and 3.30% in fiscal 2020.

The new depreciation rates were implemented retroactive to October 1, 2018.

Critical Accounting Policies and Estimates

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If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the consolidated balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred.

The write-down of the ESAC assets is consistent with the provisions of ASC No 980.

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC.

The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order;

however, the gas cost component of rates is adjusted quarterly, or more frequently if necessary, through the PGA mechanism.

When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final

however, the gas cost component of rates is adjusted

quarterly, or more frequently if necessary, through the PGA mechanism.

When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order.

Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information.

The Company has recorded an estimate for a refund related to the implementation of the new non-gas base rates effective January 1, 2019.

This estimate reflects management's evaluation of adjustments proposed by the SCC staff in their report issued on June 28, 2019, the rebuttal testimony provided by the Company and an assessment of the pending determinations from the hearing.

This estimate could change as more information becomes available and until a final order is issued.

The actual refund may be more or less than the amount included in the consolidated financial statements.

The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects.

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At the end of each WNA year, the Company refunds excess revenue collected for weather that was colder than the 30-year average or bills customers for revenue short-fall resulting from weather that was warmer than normal.

As required under the provisions of FASB ASC No.

980, Regulated Operations , the Company recognizes billed revenue related to SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

As required under the provisions of ASC No.

980, the Company recognizes billed revenue related to SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle.

The billing cycle for most customers does not coincide with the accounting periods used for financial reporting.

The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data.

The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period.

The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated.

The consolidated financial statements include unbilled revenue of $1,041,518 and $1,236,384 as of September 30, 2020 and 2019, respectively.

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Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions.

The Company outsourced its credit and collections function in 2017 as part of its strategic decision to move the call center, billing and other customer service functions to a third-party provider with significant utility experience.

These changes have been incorporated into the current valuation model for accounts receivable, which used historical information based on collection functions previously handled in-house.

The historical model used in valuing reserve for bad debts has been consistently applied over the years and has produced reasonable estimates for valuing the potential loss on customer accounts receivable.

With the arrival of COVID-19 and the related economic issues that have resulted from the pandemic, the estimation of bad debt reserves has become more subjective with greater reliance on qualitative assessments and judgement than on quantitative measures.

The potential magnitude of bad debts has been significantly increased by the moratorium, which has prevented the Company from disconnecting delinquent customers for non-payment since March 2020.

Continuing business closures and employee layoffs compound the difficulty in estimating customers' ability to meet their obligations including payment for their gas service.

The inability to limit losses due to the moratorium has significantly affected the Company's ability to estimate the level of bad debt.

Furthermore, customers that elect not to pay their gas bill or are fully unable to make payments will continue to increase bad debt levels that would otherwise be limited in the absence of such a mandate.

The Company is committed to working with its customers during these difficult times by providing extended payment terms and assisting customers in finding other sources of financial aid.

Furthermore, legislation signed into law in Virginia has provided some potential relief to utilities for the higher bad debt levels.

Under the provisions of HB5005, enacted subsequent to the end of the current fiscal year, an allotment of CARES Act funds has been made available to assist Virginia utilities in covering customer delinquent balances.

The extent to which these funds will provide relief is uncertain at this time;

however, management will take advantage of assistance that will serve both the interest of the Company and its customers.

Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees.

The expenses and liabilities associated with these plans, as disclosed in Note 9 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements.

In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies.

In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit

obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies.

Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability.

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Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, formerly the Citigroup yield curves, which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan.

The Company used a discount rate of 2.47% and 2.44%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2020.

These discount rates represent a significant decline from the 4.11% and 4.09% rates used for valuing the corresponding liabilities at September 30, 2018.

The drop in the discount rates is evidenced by the change in 30-year Treasury yield, which decreased from 3.19% last year to 2.12% at September 30, 2019 as well as corporate bond rates, which experienced a similar decline.

The reduction in the discount rates was the primary variable in increasing the benefit obligations of both the pension and the postretirement plan.

Mortality assumptions were based on the RP-2014 Mortality Table, adjusted to 2006, with generational mortality improvements using Projection Scale MP-2018 for the current year valuation.

Over the last few years, management has focused on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk.

In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested employees who were not receiving payments under the plan.

These discount rates represent a decline from the 3.03% and 3.00% rates used for valuing the corresponding liabilities at September 30, 2019.

The reduction in the discount rates corresponds to the Federal Reserve's actions to support and stimulate the economy through the reduction in interest rates in response to the economic effects arising from COVID.

The yield on the 30-year Treasury declined from 2.12% last year to 1.46% at September 30, 2020.

Corporate bond rates experienced a similar decline.

The decline in the discount rates was the driving force in increasing the benefit obligations of both the pension and the postretirement plan.

Mortality assumptions were based on the PRI-2012 Mortality Table with generational mortality improvements using Projection Scale MP-2019 for the current year valuation.

Management has continued to focus on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk.

In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested former employees who were not receiving payments under the plan.

In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate.

Employees hired prior to that date continue to accrue benefits based on compensation and years of service.

This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement medical plan.

These strategies have reduced liability growth by not allowing new employees into the plans and reducing the number of participants entitled to future benefits.

This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement plan.

The Company has again offered a one-time lump-sum payout option of deferred pension benefits to those current vested terminated employees not currently receiving pension benefits.

This offer was made in October 2020 and the lump sum payments made December 1, 2020 totaled $717,197 and removed approximately $965,000 in pension plan liabilities.

These strategies have served to limit liability growth.

The Company also has focused on its asset investment strategy.

An aggressive funding strategy combined with strong investment returns have allowed pension plan assets to increase by $10.5 million over the last three years, while liabilities increased only $6.1 million during the same period for the reasons noted above.

As of September 30, 2019, the pension plan is at a 94% funded status.

With future pension liability growth associated with increasing benefits limited to employees hired prior to the freeze, the Company evaluated measures that would mitigate the effect of changing interest rates on the pension liability.

An aggressive funding strategy combined with investment returns have allowed pension plan assets to increase by $11.2 million over the last three years, while liabilities increased by $10.3 million during the same period for the reasons noted above.

As of September 30, 2020, the pension plan is 94% funded.

Future pension liability growth associated with increasing market value is limited to employees hired prior to the freeze.

The Company desired to mitigate the volatility of the pension plan's funded status due the effect of changing interest rates on the pension liability.

As the pension liability represents the present value of future pension payments, an increase in the discount rate used to value the pension obligation would reduce the liability while a reduction in the discount rate would lead to an increase in the pension liability.

With plan funded status above 90%, the Company moved to a more conservative asset allocation model in fiscal 2018 by transitioning from a 60% equity and 40% fixed income allocation to a 40% equity and 60% fixed income allocation for pension assets.

The fixed income portion of the investments were invested using an LDI approach.

As the pension plan's funded status has continued to exceed 90%, the Company continued to increase the allocation of the plan's assets to fixed income investments as more of the plan's liability change is related to changes in the discount rate and the service accrual portion continues to become less of a factor due to the plan being frozen to new employees.

During fiscal 2020, the targeted asset allocation transitioned from 40% equity and 60% fixed income to 30% equity and 70% fixed income.

The fixed income portion of the investments are invested using an LDI approach with the fixed income assets invested with a duration that corresponds to the duration of the corresponding liability for benefits.

As a result, the valuation of the fixed income investments will move inversely to the corresponding pension liabilities as a result of changes in interest rates, which in turn will reduce the volatility in the plan's funded status and expense.

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The Company will continue to evaluate the investment allocation as the liabilities mature and the funded status continues to improve and make adjustments as necessary.

The Company has not made a change in investment allocation for the postretirement assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential.

Though not to the same magnitude, the postretirement plan assets increased by $2 million and liabilities decreased by $0.5 million over the last three-year period.

The Company has not made a change in investment allocation for the postretirement plan assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential.

The postretirement plan assets increased by $1.4 million and liabilities decreased by $0.3 million over the last three-year period.

A summary of the funded status of both the pension and postretirement plans is provided below:

Funded status - September 30, 2019

Postretirement

Funded status - September 30, 2020 Pension Postretirement Total

Benefit Obligation $ 39,998,002 $ 17,925,409 $ 57,923,411

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Funded status $ (2,340,371) $ (3,809,156) $ (6,149,527)

Funded status - September 30, 2018

Postretirement

Funded status - September 30, 2019 Pension Postretirement Total

Benefit Obligation $ 35,550,987 $ 18,030,399 $ 53,581,386

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The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans.

Understanding the volatility in the markets, the Company reviews both plans' potential

long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions.

Under the current allocation model for the pension plan, management determined that a 5.50% long-term rate of return assumption remained appropriate considering the asset allocation and market environment.

Likewise, as the asset allocation remained unchanged for the postretirement plan, management determined that a 4.26% expected long-term rate of return is reasonable.

Understanding the volatility in the markets, the Company reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions.

Under the current allocation model for the pension plan, management lowered the long-term rate of return assumption from 5.50% in fiscal 2020 to 5.40% in fiscal 2021 based on the change in the targeted equity allocation of the pension plan assets.

The long-term rate of return was virtually unchanged for the postretirement plan at 4.26% as the asset allocation remains at 50% equity and 50% fixed income.

Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year.

However, management plans to continue its pension funding plan by contributing at least the minimum annual pension contribution requirement or its expense level for subsequent years.

The Company currently expects to contribute approximately $800,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2020 with an ongoing goal to improve both plans' funded status.

However, the Company currently expects to contribute approximately $500,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2021.

The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.

Actuarial Assumptions - Pension Plan

Change in Assumption

Increase in Pension Cost

Increase in Projected Benefit Obligation

Actuarial Assumptions - Pension Plan Change in Assumption Increase in Pension Cost Increase in Projected Benefit Obligation

Discount rate -0.25 % $ 161,000 $ 1,728,000

Rate of return on plan assets

Rate of return on plan assets -0.25 % 93,000 N/A

Rate of increase in compensation 0.25 % 61,000 324,000

The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.

Actuarial Assumptions - Postretirement Plan

Change in Assumption

Increase in Postretirement Benefit Cost

Increase in Accumulated Postretirement Benefit Obligation

Actuarial Assumptions - Postretirement Plan Change in Assumption Increase in Postretirement Benefit Cost Increase in Accumulated Postretirement Benefit Obligation

Discount rate -0.25 % $ 42,000 $ 771,000

Rate of return on plan assets

Rate of return on plan assets -0.25 % 32,000 N/A

Medical claim cost increase 0.25 % 85,000 735,000

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Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements.

The Company had three interest-rate swaps outstanding at September 30, 2019 related to the three variable rate notes held by the Company.

See Note 7 for additional information regarding the swaps.

The Company had three interest-rate swaps outstanding at September 30, 2020 related to its three variable rate notes.

See Note 7 to the consolidated financial statements for additional information regarding the swaps.

Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

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-K

Item 7. Management’s Discussion and Analysis