COVID-19





As was discussed under Item 1A "Risk Factors" above, COVID-19 and the resulting
pandemic continues to impact the local, state, national and global
economies. Supply chain disruptions, labor shortages and inflation have
supplanted quarantines and government restrictions as the primary examples of
matters impacting economic conditions. Significant progress was made in
distributing and administering vaccines to the public through September 30,
2021, which has allowed a return to mostly normal operating conditions. Most
restrictions implemented as a result of the pandemic have been eased, including
Virginia's state of emergency, allowing for increased business, recreational and
travel activities. Natural gas consumption by the Company's commercial customers
has largely returned to pre-pandemic levels. However, the easing of restrictions
and the existence of variant strains of COVID-19 may lead to a rise
in infections, which could result in the reinstatement of some or all of the
restrictions previously in place. Management continues to monitor current
conditions to ensure the continuation of safe and reliable service to customers
and to maintain the safety of the Company's employees.

See the Regulatory section below for information regarding the service disconnection moratorium, CARES Act and ARPA funds.





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 increase or reduction in governmental restrictions to
businesses and individuals, the potential resurgence of the virus, including
variants, as well as efficacy of the vaccines.



Cyber Risk



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.



Overview



Resources is an energy services company primarily engaged in the regulated sale
and distribution of natural gas to approximately 62,600 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
more than 1% investor in the MVP and a less than 1% investor in Southgate. More
information regarding the investment in MVP is provided under the Equity
Investment in Mountain Valley Pipeline section below.



                                       17
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The utility operations of Roanoke Gas are regulated by the SCC, which oversees
the terms, conditions and rates charged to customers for natural gas service,
safety standards, extension of service and depreciation. Nearly all 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 based on rates
authorized by the SCC. 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 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.



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-off $317,000 of ESAC assets that were not subject to recovery
under the final order.



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 and PGA.



The Company's non-gas base rates provide for the recovery of non-gas related
expenses and a reasonable return to shareholders. 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. The investment in replacing and upgrading existing
infrastructure is generally not recoverable until a formal rate application is
filed to include the additional investment, and new non-gas base rates are
approved. The SAVE Rider provides the Company with a mechanism through which it
recovers the cost related to SAVE qualified infrastructure investments on a
prospective basis, until a formal rate application is filed to incorporate the
recovery of these costs in non-gas rates.  The SAVE Plan and Rider were reset
effective January 1, 2019, when the recovery of all prior SAVE Plan investment
was incorporated into the current non-gas rates. Accordingly, SAVE Plan revenues
increased to $2,487,000 in fiscal 2021 from $1,272,000 in fiscal 2020.  The
current SAVE Plan is focused on replacing first generation, pre-1973 plastic
pipe and other qualifying infrastructures projects. Additional information
regarding the SAVE Plan and Rider is provided under the Regulatory section.



The WNA model reduces the volatility in earnings due to the variability in
temperatures during the heating season. The WNA is based on the most recent
30-year temperature average and provides the Company with a level of earnings
protection when weather is warmer than normal and provides its customers with
price protection when the weather is colder than normal. 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 each
WNA year, which runs from April to March. The Company recorded approximately
$1,196,000 and $1,193,000 in additional revenue from the WNA for weather that
was approximately 8% warmer than normal for the fiscal years ended September 30,
2021 and 2020.  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
historical colder years, the number of heating degree days that defines normal
has declined over the last several years.



                                       18
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The Company also has an approved rate structure in place that mitigates the
impact of financing costs of its natural gas inventory. Under this rate
structure, Roanoke Gas recognizes revenue by applying the ICC factor, based on
the Company's weighted-average cost of capital, including interest rates on
short-term and long-term debt, and the Company's authorized return on equity, to
the average cost of natural gas inventory.  Total ICC revenues were $396,000 and
$389,000 for the fiscal years ended September 30, 2021 and 2020, respectively.
Average inventory balances varied modestly between periods; however, rising
natural gas commodity prices near the end of the current fiscal year may lead to
higher ICC revenues in fiscal 2022.



The cost of natural gas is a pass-through cost and is independent of the non-gas
rates of the Company. Accordingly, 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. This rate component, referred to as the PGA, allows the
Company to pass along to its customers increases and decreases in natural gas
costs based on a quarterly filing, or more frequent if necessary, with the SCC.
Once administrative approval is received, the Company adjusts the gas cost
component of its rates to reflect the approved amount. As actual costs will
differ from the projections used in establishing the PGA rate, the Company will
either over-recover or under-recover its actual gas costs during the period. The
difference between actual costs incurred and costs recovered through the
application of the PGA is recorded as a regulatory asset or liability. 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.



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
conducted preliminary earnings tests for fiscal 2021 and 2020 in preparation for
the AIF filings in January of the subsequent years.  As a result of the
preliminary earnings tests, Roanoke Gas expensed $217,000 in deferred COVID
costs incurred during fiscal 2021, and fully amortized the remaining $525,000
balance of ESAC assets in fiscal 2020.



Inflation and Rising Prices



Natural gas commodity, delivery and storage capacity costs comprise the single
largest expense of the Company representing nearly 58% of fiscal 2021 total
operating expenses.  Natural gas commodity prices have steadily increased
through fiscal 2021 and natural gas futures for the upcoming winter heating
season are double September prices.  Several factors have contributed to rising
natural gas prices including lack of interstate pipeline development, demand
rebounding as activity returns to pre-pandemic levels, lower inventory storage
levels, increased demand for cleaner energy and lagging production from
suppliers.  Roanoke Gas can recover rising natural gas costs through the PGA
mechanism as noted above; however, in times of rapidly increasing costs, the
timing of recovery may lag.  Increasing natural gas prices, especially in
relation to other energy options, may lead to reductions in energy consumption
through customer conservation or fuel switching in addition to the potential for
rising bad debts related to customers inability to pay higher natural gas bills.



Inflation affects the Company through increases in non-gas expenses such as
labor costs, employee benefits, materials and supplies, contracted services and
corporate insurance, among other areas.  As the country emerges from the
pandemic, issues such as supply chain delays, labor shortages and limited
availability of key or critical supplies have put upward pressure on several
categories of the Company's non-gas expenses.  The Company recovers non-gas
related costs through the non-gas portion of its tariff rates, which are
adjusted through a non-gas rate application. Unlike the rate adjustments for the
gas portion of rates which are done administratively, the non-gas rate
application results in an inherent lag in non-gas expense recovery.
Therefore, authorized non-gas rates may not keep pace with the rising costs
during inflationary periods.  Management must regularly evaluate the Company's
operations, economic conditions and other factors to assess the need
to apply for a non-gas rate adjustment.





                                       19

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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 Midstream's investment in affiliates represents a significant component of the comparison.





The Company's operating revenues are affected by the cost of natural gas, as
reflected in the consolidated income statement under the line item cost of gas -
utility. The cost of natural gas is passed through to customers at cost, which
includes commodity price, transportation, storage, injection and withdrawal fees
with any increase or decrease offset by a correlating change in revenue through
the PGA. 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 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 2021 Compared with Fiscal Year 2020





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



Operating Revenues
                                                                           Increase /
Year Ended September 30,                    2021             2020         

(Decrease)        Percentage
Gas Utility                             $ 75,045,103     $ 62,408,925     $  12,636,178               20 %
Non Utility                                  129,676          666,466          (536,790 )            (81 )%
Total Operating Revenues                $ 75,174,779     $ 63,075,391     $  12,099,388               19 %




Delivered Volumes
                                                                          Increase /
Year Ended September 30,                   2021             2020          (Decrease)       Percentage
Regulated Natural Gas (DTH)
Residential and Commercial                6,773,819        6,419,031          354,788                6 %

Transportation and Interruptible 3,135,710 3,938,143 


 (802,433 )            (20 )%
Total Delivered Volumes                   9,909,529       10,357,174         (447,645 )             (4 )%
HDD                                           3,610            3,623              (13 )             (0 )%




Total gas utility operating revenues for the year ended September 30,
2021 increased by 20% from the year ended September 30, 2020 primarily due to
higher natural gas commodity prices and pipeline storage fees, higher
residential and commercial volumes and an increase in SAVE revenues, partially
offset by lower transportation and interruptible volumes.  Rising natural gas
commodity prices combined with higher transportation fees implemented by the
Company's pipeline suppliers have resulted in a 41% per dth increase in the
commodity component of revenue and a 38% per dth increase in the demand
(pipeline and storage fees) component of revenue.  These higher gas costs are
passed on to customers through the PGA mechanism. The mostly weather sensitive
residential and commercial natural gas deliveries increased by 6% on nearly the
same number of heating degree days.  The higher deliveries reflect the increased
demand for natural gas as economic conditions continue to improve and the
economy emerges from last year's pandemic.  SAVE Plan revenues increased by
$1,215,000  due to the ongoing investment in qualified SAVE infrastructure
projects.  Transportation and interruptible volumes, primarily driven by
business activity rather than weather, declined by 20% due to a single
multi-fuel customer that switched its primary fuel from natural gas to an
alternate energy source in response to rising natural gas prices.  In early
fiscal 2020, this same customer switched from another energy source to natural
gas as its primary fuel due to the favorable pricing of natural gas.  Excluding
the multi-fuel customer's usage from both periods, total transportation and
interruptible volumes would have increased by 3% on a comparative basis.
Non-utility revenues decreased due to the completion of a significant long-term
contract in fiscal  2020.



                                       20

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Gross Utility Margin

Year Ended September 30,       2021             2020           Increase        Percentage
Gas Utility Revenues       $ 75,045,103     $ 62,408,925     $ 12,636,178               20 %
Cost of Gas - Utility        35,179,842       23,949,481       11,230,361               47 %
Gross Utility Margin       $ 39,865,261     $ 38,459,444     $  1,405,817                4 %




Gross utility margin increased over the prior fiscal year primarily as a result
of the aforementioned higher SAVE revenues and increase in residential and
commercial volumes and customer base charges more than offsetting the reduction
in transportation and interruptible deliveries. Total volumetric margin
increased for the reasons mentioned above as the increase in residential and
commercial DTH sales more than offset the decline in lower-margin interruptible
and transportation volumes.  The growth in customer base charge revenues reflect
a combination of customer additions and the continuation of service to
delinquent customers as a result of the disconnection moratorium, which ended
August 30, 2021.



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



                         Years Ended September 30,
                           2021              2020          Increase / (Decrease)
Customer Base Charge   $  14,563,274     $ 14,413,709     $               149,565
SAVE Plan                  2,487,299        1,272,070                   1,215,229
Volumetric                21,188,794       21,091,007                      97,787
WNA                        1,196,499        1,192,715                       3,784
Carrying Cost                395,626          388,607                       7,019
Other Revenues                33,769          101,336                     (67,567 )
Total                  $  39,865,261     $ 38,459,444     $             1,405,817




Operations and Maintenance Expense - Operations and maintenance expense
decreased by $1,703,874 or 11%, from the prior year primarily due to the
accelerated recovery of ESAC regulatory assets in fiscal 2020 and lower bad debt
expense, partially offset by lower capitalized overheads. In accordance with the
SCC's final order on the non-gas base rate application, the Company wrote-down
$317,000 in ESAC assets last year that were not subject to recovery through the
new rates.  In addition to the write-down of a portion of the ESAC assets in
December 2019, Roanoke Gas accelerated the recovery of the remaining $525,000
balance of ESAC assets in September 2020 as a result of the earnings test
performed by the Company. Bad debt expense declined by $964,000 due to the
application of more than $400,000 in CARES Act funds to eligible COVID-19
impacted customers with past due balances and the pending receipt of $859,000 in
ARPA funds to provide similar relief.  If not for the CARES Act and ARPA funds,
bad debt expense would have increased significantly over last year's higher than
normal levels.  Total capitalized overheads declined by $258,000 on a nearly $3
million reduction in capital expenditures related to project timing.



                                       21
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General Taxes - General taxes increased by $95,307, or 4%, primarily due to higher property taxes associated with a 5% increase in utility property.

Depreciation - Depreciation expense increased by $533,895, or 7%, corresponding to a similar increase in depreciable utility plant.





Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the
MVP investment decreased by $3,147,320 as AFUDC activity ceased during the
second fiscal quarter due to the cessation of growth construction activities by
the LLC with limited construction resuming in April 2021 resulting in a much
lower level of AFUDC recognized for the remainder of the year.  See the Equity
Investment in Mountain Valley Pipeline section for additional information.



Other Income, net - Other income increased by $275,850 primarily due to a
$449,000 decrease in the non-service cost components of net periodic benefit
costs partially offset by $207,000 reduction in the equity portion of AFUDC on
Roanoke Gas' two gate stations that will interconnect with the MVP.  Roanoke Gas
temporarily stopped recognizing AFUDC effective January 2021 until such time
construction activities resume on these stations.



Interest Expense - Total interest expense decreased by $47,273, or 1%, as a
decline in the interest rate on the Company's variable rate debt offset higher
total debt levels.  Total average debt outstanding increased by 14% to meet the
funding needs of Roanoke Gas' capital projects and Midstream's continuing
investment in MVP.  As a result of the declining interest rates on the Company's
variable rate debt, the weighted-average interest rate fell by 12%.  Declines in
other interest contributed to the lower expense levels including lower customer
deposit interest.

Roanoke Gas' interest expense increased by $81,285 as total average debt outstanding increased by $8,500,000 associated with an increase in the borrowings under the line-of-credit. The average interest rate decreased slightly from 3.76% in fiscal 2020 to 3.48% in fiscal 2021. Roanoke gas capitalized $68,000 less in AFUDC during the current year due to the absence of construction activities on the two gate stations, which offset a $67,000 reduction in interest expense attributable to fiscal 2020's rate refund.





Midstream's interest expense decreased by $128,558 as the average interest rate
on Midstream's total debt declined from 2.76% to 2.23% related to the variable
interest rate credit facility more than offsetting a $6,900,000 increase in
total average debt outstanding during the period.



Income Taxes - Income tax expense decreased by $101,598, or 3%, on a 4% decrease
in pre-tax earnings. The effective tax rate was 24.1% for fiscal 2021 compared
to 23.8% for fiscal 2020. 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, the excess deductions related to restricted
stock vesting, stock option exercises and the realization of certain tax
credits. Income tax expense related to Midstream decreased by $780,000 due to
the significant reduction in pre-tax earnings related to AFUDC from the MVP
investment. The majority of the remaining $680,000 difference in income tax
expense is related to the increase in pre-tax earnings of Roanoke Gas.



Net Income and Dividends - Net income for fiscal 2021 was $10,102,062 compared
to $10,564,534 for fiscal 2020. Basic and diluted earnings per share were
$1.22 in fiscal 2021 compared to $1.30 in fiscal 2020. Dividends declared per
share of common stock were $0.74 in fiscal 2021 compared to $0.70 in fiscal
2020.

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 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 relies on its operating cash flows, credit availability under
short-term and long-term debt agreements and proceeds from the sale of its
common stock.



                                       22

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Cash and cash equivalents increased by approximately $1.2 million in fiscal 2021 compared to a decrease of $1.3 million in fiscal 2020. The following table summarizes the categories of sources and uses of cash:





Cash Flow Summary                                               Years Ended September 30,
                                                                 2021              2020
Net cash provided by operating activities                    $  11,568,108     $  12,823,903
Net cash used in investing activities                          (25,849,237 )     (30,721,011 )
Net cash provided by financing activities                       15,508,380

16,556,826

Net increase (decrease) in cash and cash equivalents $ 1,227,251

   $  (1,340,282 )

Cash Flows Provided by Operating Activities:





The seasonal nature of the natural gas business causes operating cash flows to
fluctuate significantly during the year, as well as from year to year. 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 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 $1.3 million from the
prior year. The decrease in cash flow provided by operations was primarily
driven by the affects of increasing gas commodity prices and changes in certain
regulatory assets and liabilities, partially offset by net income exclusive of
noncash equity in earnings.

The table below summarizes the significant operating cash flow components:





                                                    Years Ended September 30,
                                                                                       Increase
Cash Flows From Operating Activities:                 2021              2020          (Decrease)
Net Income                                        $  10,102,062     $ 10,564,534     $    (462,472 )
Non-cash adjustments:
Depreciation                                          8,669,977        8,126,427           543,550
Equity in earnings                                   (1,667,554 )     (4,814,874 )       3,147,320
AFUDC                                                   (55,981 )       (330,208 )         274,227
Allowance for doubtful accounts                        (461,130 )        592,398        (1,053,528 )
ESAC assets                                                   -        1,022,195        (1,022,195 )
Changes in working capital and regulatory
assets and liabilities:
Accounts receivable                                  (1,084,726 )       (141,482 )        (943,244 )
Gas in Storage                                       (2,158,709 )        739,546        (2,898,255 )
Prepaid income taxes                                 (2,457,327 )        510,357        (2,967,684 )
Accounts payable and accrued expenses                 2,862,861          659,276         2,203,585
Deferred Taxes                                          106,188        1,327,655        (1,221,467 )
Change in over (under) collection of gas costs       (3,314,446 )     (1,895,555 )      (1,418,891 )
Rate refund                                                   -       (3,827,589 )       3,827,589
WNA                                                    (609,888 )      1,171,342        (1,781,230 )
Non-current regulatory liabilities                    2,367,512                -         2,367,512
Other                                                  (730,731 )

(880,119 ) 149,388 Net cash provided by operating activities $ 11,568,108 $ 12,823,903 $ (1,255,795 )






Increasing natural gas commodity prices during 2021, resulted in reductions in
operating cash in several areas. Higher accounts receivable balances, and
increases in the under collection of gas costs, and rising gas in storage
balances resulted in lower operating cash of $0.9, $1.4 and $2.9 million year
over year, respectively. Income tax refunds not yet received, associated with
the R&D credit study conducted by a third party consultant, caused prepaid
income taxes to increase significantly year over year, resulting in a decrease
in operating cash of $3 million. See Note 8 for more information regarding the
R&D tax credit.



                                       23

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Operating cash decreases were partially offset by accounts payable and changes
in certain regulatory assets and liabilities. Significantly higher accounts
payable balances related to increasing natural gas commodity prices provided an
additional $2.2 million in operating cash year over year. As there was no rate
refund in fiscal 2021, operating cash improved $3.8 million.

Other significant non-cash changes include $1.1 million for allowance for doubtful accounts due to changes in bad debt reserves attributable to the pandemic and funding relief and $2.4 million related to the establishment of a regulatory liability for the R&D tax credit.

Cash Flows Used in Investing Activities:





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 $20 million and $22.9 million in
fiscal 2021 and 2020, respectively. Roanoke Gas renewed 7.8 miles of main and
620 service lines and 9.6 miles of main and 592 service lines in fiscal years
2021 and 2020, respectively. The current SAVE Plan is focused on the replacement
of pre-1973 first generation plastic pipe in addition to other SAVE related
infrastructure. Furthermore, Roanoke Gas' capital expenditures included costs to
extend natural gas distribution mains and services to480 customers in fiscal
2021, compared to 448 customers in fiscal 2020. Depreciation covered
approximately 43% and 35% of the current and prior year's capital expenditures,
respectively, with the balance provided from other operating cash flows and
financing activities.



Capital expenditures are expected to remain at or near current levels over the
next three to five years as Roanoke Gas continues to focus on its SAVE Plan,
which is expected to be completed by 2024, as well as customer growth and system
expansion. 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 2021 funding of $6 million for Midstream's
participation in the LLC. Midstream's total expected funding requirement
increased to between $60 and $62 million as discussed below, with anticipated
cash investment for fiscal 2022 to be approximately $10.7 million. Funding for
the investment in the LLC is provided through Midstream's credit facility and
two unsecured notes in the combined amount of $24 million. More information
regarding the credit facility 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 credit
agreements, issuance of stock and the payment of dividends. Net cash flows
provided by financing activities were $15.5 million and $16.6 million in fiscal
2021 and 2020, 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 $8 million to finance its investment in MVP. The Company
also realized $3.3 million from the issuance of common stock through its ATM
program and $1.6 million from the issuance of stock through DRIP activity and
the exercise of options. Cash out-flows for dividend payments exceeded $6.0
million as the annualized dividend rate increased from $0.70 to $0.74 per share.
The Company's consolidated capitalization was 41.5% equity and 58.5% long-term
debt at September 30, 2021, exclusive of unamortized debt expense. This compares
to 41.7% equity and 58.3% long-term debt at September 30, 2020.



                                       24
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On October 29, 2021 Midstream entered into an unsecured promissory note in the
principal amount of $8 million with an interest rate based on 30-day LIBOR plus
115 basis points maturing December 1, 2027. Related to this note, Midstream also
entered into an interest rate swap agreement that effectively converts the
variable rate note into a fixed rate instrument with an effective annual
interest rate of 2.443%. The loan will convert into an installment loan with
principal pay-down beginning in fiscal 2023. In addition, this note reduces the
borrowing capacity defined by the Third Amendment to Credit Agreement
and related Promissory Notes. The total borrowing capacity declined from $41
million to $33 million effective with the new promissory note.  All other terms
of the Third Amendment to Credit Agreement remain unchanged.



On September 24, 2021, Roanoke Gas entered into an unsecured Delayed Draw Term
Note in the principal amount of $10 million with an interest rate based on
30-day LIBOR plus 100 basis points maturing on October 1, 2028. Related to this
note, the Company also entered into an interest rate swap agreement that
effectively converts the variable rate note into a fixed rate instrument with an
effective annual interest rate of 2.49%. The term note will fund in two
installments of $5 million each on April 1, 2022 and October 1, 2022,
respectively.



On August 20, 2021, Roanoke Gas entered into an unsecured Delayed Draw Term Note
in the principal amount of $15 million with an interest rate of 1.20% above the
30-day SOFR Average per annum maturing on August 20, 2026. Related to this note,
the Company also entered into an interest rate swap agreement that effectively
converts the variable rate note into a fixed rate instrument with an effective
annual interest rate of 2.00% The term note funded on October 1, 2021.



On March 25, 2021, Roanoke Gas renewed its unsecured line-of-credit
agreement for a two-year term expiring March 31, 2023 with a maximum borrowing
limit of $40 million. 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 $14 million to $40 million.



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



Roanoke Gas has private shelf agreements with two different financial
institutions.  The first agreement, as amended, provides for the issuance of up
to $40 million in unsecured notes in addition to the $28 million previously
issued.  This shelf agreement will expire on December 6, 2022 unless extended.
The second agreement, effective September 30, 2020, provides for the issuance of
up to $70 million in unsecured notes during its 5-year term expiring on
September 30, 2025.  No funds were drawn on either of these agreements during
fiscal 2021.



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 million. The prospectus
was filed including a supplement allowing the Company to offer a portion of
these shares, up to an aggregate of $15 million, utilizing the ATM approach as
defined in Rule 415 under the Securities Act. The ATM Plan allows Resources
flexibility in the frequency, timing and amount of share offerings in
supplementing its capital funding needs. There were 142,726 shares issued
through the ATM program during fiscal 2021.

Off-Balance Sheet Arrangements

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

Equity Investment in Mountain Valley Pipeline





Recent construction activity has been limited based on legal and regulatory
challenges. Although certain permits and authorizations were received in the
fourth quarter of fiscal 2020 and the first quarter of fiscal 2021, there remain
pending challenges and authorization requests impacting current progress.



                                       25
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Following a comprehensive review of all outstanding stream and wetland crossings
across the approximately 300-mile MVP project route, on February 19, 2021, the
LLC submitted (i) a joint application package to each of the Huntington,
Pittsburgh and Norfolk Districts of the U.S. Army Corps of Engineers (Army
Corps) that requests an individual permit from the Army Corps to cross certain
streams and wetlands utilizing open cut techniques (the Army Corps Individual
Permit) and (ii) an application to amend the MVP project's CPCN that seeks FERC
authority to cross certain streams and wetlands utilizing alternative trenchless
construction methods.



Related to seeking the Army Corps Individual Permit, on March 4, 2021, the LLC
submitted applications to each of the West Virginia Department of Environmental
Protection (WVDEP) and the Virginia Department of Environmental Quality (VADEQ)
seeking Section 401 water quality certification approvals or waivers (such
approvals or waivers, the State 401 Approvals).  Both the WVDEP and VADEQ
submitted requests to the Army Corps for additional time to address the
applications, and in late June 2021, the Army Corps granted the WVDEP and the
VADEQ additional review time through November 29, 2021 and December 31, 2021,
respectively.  In early June 2021, the FERC issued a notice of schedule for the
LLC's CPCN amendment application. FERC issued its environmental assessment
August 13, 2021.  Given that the expected permitting timelines for both the FERC
and the Army Corps remain in-line with the LLC's expectations, the LLC continues
to target a full in-service date for the MVP project in summer 2022 at a total
project cost of approximately $6.2 billion (excluding AFUDC).



In order to complete the MVP project in accordance with the targeted full
in-service date and cost, the LLC must, among other things, timely receive the
Army Corps Individual Permit (as well as timely receive the State 401 Approvals
and, as necessary, certain other state-level approvals) and timely receive
authorization from the FERC to amend the CPCN to utilize alternative trenchless
construction methods for certain stream and wetland crossings. The LLC also
must (i) maintain and, as applicable, timely receive required authorizations,
including authorization to proceed with construction, related to the Jefferson
National Forest from the Bureau of Land Management, the U.S. Forest Service and
the FERC; (ii) continue to have available the orders previously issued by the
FERC modifying its prior stop work orders and extending the LLC's prescribed
time to complete the MVP project; (iii) timely receive authorization from the
FERC to complete construction work in the portion of the project route currently
remaining subject to the FERC's previous stop work order; and (iv) continue to
be authorized to work under the Biological Opinion and Incidental Take Statement
issued by the United States Department of the Interior's Fish and Wildlife
Service for the MVP project. In each case, any such foregoing or other
authorizations must remain in effect notwithstanding any pending or future
challenge thereto. Failure to achieve any one of the above items could lead to
additional delays and higher project costs.



Resources' current earnings from the MVP investment are attributable to AFUDC
income generated by the LLC. The LLC temporarily suspended the accrual of AFUDC
on the project from January 1, 2021 (due to a temporary reduction in
growth construction activities) through March 31, 2021.  Limited
growth construction activities resumed in April 2021, and the LLC began accruing
AFUDC associated with those activities.  It is expected that the accrual of
AFUDC will be temporarily suspended again for the winter curtailment period,
which is expected to begin around November 2021. Additionally, Roanoke Gas
continues the suspension of AFUDC accruals on its two gate stations that will
interconnect with the MVP until such time as construction activities resume on
the respective gate stations.



Management conducted an assessment of its MVP investment in accordance with the
provisions of ASC 323, Investments - Equity Method and Joint Ventures. This
assessment included a third-party valuation. As a result of its evaluation,
management has concluded that the investment is not currently impaired as of
September 30, 2021. Furthermore, the LLC has conducted its own evaluation of the
project and also concluded that no impairment exists as of September 30, 2021.
Management will continue monitoring the status of the project for circumstances
that may lead to future impairment, including any significant delays or denials
of necessary permits and approvals. If necessary, the amount and timing of any
future impairment would be dependent on the specific circumstances at the time
of evaluation.



                                       26

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In April 2018, the LLC announced the MVP Southgate project and submitted
Southgate's certificate application to the FERC in November 2018. The Final
Environmental Impact Statement for the project was issued on February 14, 2020.
In June 2020, the FERC issued the CPCN for the MVP Southgate; however, the FERC,
while authorizing the project, directed the Office of Energy Projects not to
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. On August 11, 2020, the North Carolina Department of Environmental Quality
(NCDEQ) denied Southgate's application for a Clean Water Act Section 401
Individual Water Quality Certification and Jordan Lake Riparian Buffer
Authorization due to timing of the MVP project's completion. On March 11, 2021,
the Fourth Circuit Court of Appeals, pursuant to an appeal filed by the LLC,
vacated the NCDEQ's denial and remanded the matter to the NCDEQ for additional
review. On April 29, 2021, the NCDEQ reissued its denial of
Southgate's application. Based on the targeted full in-service date for the MVP
and expectations regarding Southgate permit approval timing, the LLC is
targeting the commencement of the MVP Southgate construction in 2022 and placing
the MVP Southgate in-service during the spring of 2023.

Midstream has borrowing capacity of $41 million under its current credit facility, which matures in December 2022. As of September 30, 2021, $33.6 million had been utilized. Effective November 1, 2021, the borrowing capacity under this credit facility was reduced to $33 million as $8 million of the outstanding balance was termed out in a separate unsecured promissory note.

See


the Capital Resources and Liquidity section for more information. This credit
facility will provide additional financing capacity for MVP funding; however,
due to ongoing delays, additional financing will be required. Management is
working with the Company's lending institutions to secure the necessary
funding. If the legal and regulatory challenges, including any future
challenges, are not resolved in a timely manner and/or restrictions are imposed
that impact future construction, the cost of the MVP and Midstream's capital
contributions may increase above current projections.



Regulatory



On January 24, 2020, the SCC issued its final general rate case order awarding
Roanoke Gas an annualized non-gas rate increase of $7.25 million and providing
for a 9.44% return on equity and directing the write-off of $317,000 of ESAC
assets not subject to recovery under the approved rates. Rates authorized by the
SCC's final order required the Company to issue customers $3.8 million in rate
refunds, which was completed in March 2020.



The final order also excluded from current rates a return on the investment of
two interconnect stations with the MVP, but provided Roanoke Gas with the
ability to defer the related financing costs of those investments for possible
future recovery. As a result, the Company began recognizing AFUDC during the
second quarter of fiscal 2020 to capitalize both the equity and debt financing
costs incurred during the construction phases. During the first quarter of 2021,
Roanoke Gas recognized a total of $55,981 in AFUDC, $41,978 and $14,003 of
equity and debt carrying costs, respectively. Beginning January 2021, Roanoke
Gas temporarily ceased recording AFUDC on its related MVP interconnect
construction projects until such time as construction activities resume.



The service disconnection moratorium under which the Company has been operating
since March 16, 2020, expired August 30, 2021. During the moratorium, utilities
were prohibited from disconnecting residential customers for non-payment of
their natural gas service and from assessing late payment fees; therefore,
residential customers that ordinarily would have been disconnected for
non-payment continued incurring charges for gas service. As a result, the
Company's arrearage balances are at historically high levels, which has resulted
in a higher potential for bad debt write-offs.



In December 2020, Roanoke Gas received $403,000 in CARES Act funds to assist
customers with growing past due balances. Based on guidance provided by the SCC,
the Company was able to apply the full amount to eligible customer accounts
during the second and third fiscal quarters. On October 28, 2021, Roanoke Gas
received notification from the SCC that its application for ARPA funds has been
approved.  According to the communication, the Company will receive $858,556
based on arrearage balances as of August 31, 2021.  The pending receipt of these
funds were considered in the valuation of the estimated allowance for
uncollectibles as of September 30, 2021.



                                       27
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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. Roanoke Gas
deferred certain COVID-19 related costs throughout fiscal 2021.  Based on
Roanoke Gas's preliminary earnings test for the period ended September 30, 2021,
fiscal 2021 earnings exceeded the mid-point of the authorized return resulting
in the COVID-19 related costs being expensed during the fourth quarter.



Roanoke Gas continues to recover the costs of its infrastructure replacement
program through its SAVE Rider. In May 2021, the Company filed its most recent
SAVE application with the SCC to update the SAVE Plan and Rider for the period
October 2021 through September 2022. In its application, Roanoke Gas 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. The updated
SAVE Rider is designed to collect approximately $3.45 million in annual
revenues, an increase of approximately $1.1 million from the existing SAVE Rider
rates.  The Company received a final order on August 25, 2021 in which the SCC
approved the Company's requested revenue requirement.

Critical Accounting Policies and Estimates





The consolidated financial statements of Resources are prepared in accordance
with accounting principles generally accepted in the United States of America.
The amounts of assets, liabilities, revenues and expenses reported in the
Company's financial statements are affected by accounting policies, estimates
and assumptions that are necessary to comply with generally accepted accounting
principles. Estimates used in the financial statements are derived from prior
experience, statistical analysis and professional judgments. Actual results may
differ significantly from these estimates and assumptions.



The Company considers an estimate to be critical if it is material to the
financial statements and requires assumptions to be made that were uncertain at
the time the estimate was made and changes in the estimate are reasonably likely
to occur from period to period. The Company considers the following accounting
policies and estimates to be critical.



Regulatory accounting - The Company's regulated operations follow the accounting
and reporting requirements of FASB ASC No. 980, Regulated Operations. The
economic effects of regulation can result in a regulated company deferring costs
that have been or are expected to be recovered from customers in a period
different from the period in which the costs would be charged to expense by an
unregulated enterprise. When this occurs, costs are deferred as regulatory
assets on the consolidated balance sheet and recorded as expenses in the
consolidated statements of income and comprehensive income when such amounts are
reflected in rates. Additionally, regulators can impose regulatory liabilities
upon a regulated company for amounts previously collected from customers and for
current collection in rates of costs that are expected to be incurred in the
future.



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-downs of the COVID asset and ESAC assets are 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 order. Under these circumstances, the Company estimates the amount of
increase it anticipates will be approved based on the best available
information.



                                       28

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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. As authorized by the SCC, the Company adjusts
billed revenues monthly through the application of the WNA model. As the
Company's non-gas rates are established based on the 30-year temperature
average, monthly fluctuations in temperature from the 30-year average could
result in the recognition of more or less revenue than for what the non-gas
rates were designed. The WNA authorizes the Company to adjust monthly revenues
for the effects of variation in weather from the 30-year average with a
corresponding entry to a WNA receivable or payable. 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 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 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 $1,191,227 and $1,041,518 as of September 30, 2021
and 2020, respectively.



The Company adopted ASU 2014-09, Revenue from Contracts with Customers, and
subsequent guidance and amendments effective October 1, 2018. The adoption of
the ASU did not have a significant effect on the Company's results of
operations, financial position or cash flows as the new guidance resulted in
essentially no change in the manner and timing in which the Company recognizes
revenues. The primary operation of the Company is the sale and/or delivery of
natural gas to customers (the performance obligation) based on SCC approved
tariff rates (the transaction price). The Company recognizes revenue through
billed and unbilled customer usage as natural gas is delivered. The Company also
recognizes revenue through ARPs, including the WNA.



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 historical model used in
valuing reserve for bad debts has been consistently applied over recent years
and has produced reasonable estimates for valuing the potential loss on customer
accounts receivable. With the arrival of COVID-19 and the unprecedented
widespread impact deriving from the pandemic, including the 17 month
disconnection moratorium, the estimation of the Company's bad debt reserves has
become more subjective with greater reliance on qualitative assessments and
judgment rather than historical patterns and tendencies.  Furthermore, the
federal government has made funds available through the CARES Act and ARPA,
which have materially reduced the expected uncollectable balances as of
September 30, 2021.  Accordingly, based on management's evaluation, the total
bad debt reserves were estimated at $242,010 as of September 30, 2021.



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. With rising natural gas prices and lingering
economic effects from the moratorium and COVID, bad debt concerns will continue
into fiscal 2022.



Pension and Postretirement Benefits - The Company offers a pension plan and a
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. 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. Actual results may differ materially from the results expected
from the actuarial assumptions due to changing economic conditions, differences
in actual returns on plan assets, different rates of medical inflation,
volatility in interest rates and changes in life expectancy. 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.



                                       29
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In selecting the discount rate to be used in determining the benefit liability,
the Company utilized the FTSE Pension Discount Curve, which incorporates 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 2.73% and
2.70%, respectively, for valuing its pension plan liability and postretirement
plan liability at September 30, 2021. These discount rates represent an
increase from the 2.47% and 2.44% rates used for valuing the corresponding
liabilities at September 30, 2020. The increase in discount rates corresponds to
the inflationary pressures and current market conditions as the economy emerges
from the impact of COVID. The yield on the 30-year Treasury increased from 1.46%
last year to 2.08% at September 30, 2021. Corporate bond rates experienced a
smaller increase as credit spreads appear to have narrowed. The rise in the
discount rates was the primary factor in the reduction of the benefit
obligations for 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-2020 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 plan. In October 2020, the
Company again offered a one-time lump-sum payout option of deferred pension
benefits to those vested terminated employees not currently receiving pension
benefits. Lump sum payments of $717,197 were made to those participants that
elected this option and reduced corresponding pension liabilities by
approximately $965,000.  Each of these strategies have served to limit liability
growth and reduce volatility.



The Company also has focused on its asset investment strategy. A combination of
funding strategy and solid investment returns have allowed pension plan assets
to increase by $10.7 million over the last three years, while liabilities
increased by $8.8 million during the same period primarily due to a decline in
the discount rate for determining the liability from 4.11% at September 30, 2018
to 2.73% at September 30, 2021. As of September 30, 2021, the pension plan is
103% funded compared to 94% funded in the prior year. Future pension liability
growth associated with participant service and compensation is limited to
employees hired prior to the freeze. With the soft freeze of the pension plan,
the portion of the liability attributable to active eligible employees
continuing to accrue benefits has declined from 56% of the liability as of the
date of the soft freeze to 39% in fiscal 2021.  The remaining 61% of the 2021
liability is set subject to variability due to changes in the discount rate and
mortality adjustments.  Since January 2017 when the pension plan froze access to
new employees, the asset allocation has transitioned from a 60% equity and  40%
fixed income allocation to a 30% equity and 70% fixed income allocation.  During
the same period, the fixed income portion of the plan was transitioned to an
LDI approach with the fixed income assets invested in securities with a duration
that corresponds to the duration of the corresponding liability for benefits to
be paid.  This synchronization of 70% of the pension assets with the pension
liabilities will reduce volatility in the funded status of the plan as well as
the corresponding expense.  The 30% allocation to equity investments provides
asset growth potential to offset increases in the pension liability related to
those employees continuing to accrue benefits. Management will continue to
evaluate the investment allocation as the liabilities mature and make
adjustments as necessary.



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 $2.9 million and
liabilities increased by $0.6 million over the last three-year period.  As the
number of participants in the postretirement plan continue to decline through
attrition, management will continue to monitor and evaluate the asset allocation
and adjust as warranted.



                                       30

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

Funded status - September 30, 2021 Pension Postretirement 


  Total
Benefit Obligation                   $ 37,654,468     $     16,796,849     $ 54,451,317
Fair value of assets                   38,914,107           15,882,342       54,796,449
Funded status                        $  1,259,639     $       (914,507 )   $    345,132

Funded status - September 30, 2020 Pension Postretirement 


  Total
Benefit Obligation                   $ 39,998,002     $     17,925,409     $ 57,923,411
Fair value of assets                   37,657,631           14,116,253       51,773,884
Funded status                        $ (2,340,371 )   $     (3,809,156 )   $ (6,149,527 )




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 lowered the long-term rate of return
assumption from 5.40% in fiscal 2021 to 4.75% in fiscal 2022 based on the change
in the current equity allocation of the pension plan assets and the lower rate
of return expected on the fixed income investments. The long-term rate of return
was virtually unchanged for the postretirement plan at 4.25% 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, the Company currently expects to contribute approximately
$500,000 to its pension plan and $400,000 to its postretirement plan in fiscal
2022. 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.



                                                                                     Increase in
                                                                                      Projected
                                             Change in           Increase in           Benefit
Actuarial Assumptions - Pension Plan         Assumption         Pension Cost          Obligation
Discount rate                                        -0.25 %   $       143,000     $      1,547,000
Rate of return on plan assets                        -0.25 %            96,000                  N/A
Rate of increase in compensation                      0.25 %            57,000              285,000




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.



                                                                                             Increase in
                                                                                             Accumulated
                                                                       Increase in          Postretirement
                                                 Change in           Postretirement            Benefit

Actuarial Assumptions - Postretirement Plan Assumption Benefit Cost

            Obligation
Discount rate                                            -0.25 %   $            41,000     $        652,000
Rate of return on plan assets                            -0.25 %                35,000                  N/A
Medical claim cost increase                               0.25 %                83,000              620,000




Derivatives - The Company may hedge certain risks incurred in its operation
through the use of derivative instruments. The Company applies the requirements
of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of
derivative instruments as assets or liabilities in the Company's consolidated
balance sheet at fair value. In most instances, fair value is based upon quoted
futures prices for natural gas commodities and interest rate futures for
interest rate swaps. Changes in the commodity and futures markets will impact
the estimates of fair value in the future. 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, 2021
related to its three variable rate notes and two interest-rate swaps associated
with delayed draw notes to be funded subsequent to fiscal 2021. See Note 7 to
the consolidated financial statements for additional information regarding the
swaps.



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