COVID-19



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 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.









                                       16

--------------------------------------------------------------------------------

Overview



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
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 annual revenues 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 and depreciation. 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.
The SCC authorizes the rates and fees the Company charges its customers for
these services. 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.

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. 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 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 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 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
                                       17
--------------------------------------------------------------------------------

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. 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 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 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. Under this rate
structure, Roanoke Gas recognizes revenue for the financing costs, or "carrying
costs," of its investment in natural gas inventory. The ICC factor applied to
average inventory is 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.

During times of rising gas costs and rising inventory levels, Roanoke Gas
recognizes ICC revenues to offset higher financing costs associated with higher
inventory balances. Conversely, during times of decreasing gas costs and
declining inventory balances, Roanoke Gas recognizes less ICC revenue as
financing costs are lower. In addition, ICC revenues are impacted by changes in
the weighted-average cost of capital. 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. 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 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. On at least a quarterly basis, the Company
files a PGA rate adjustment request with the SCC to adjust the gas cost
component of its rates up or down depending on projected price and activity.
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'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.

                                       18
--------------------------------------------------------------------------------

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 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.
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 2020 Compared with Fiscal Year 2019



The table below reflects operating revenues, volume activity and heating degree
days.
     Operating Revenues
     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,                 2020                      2019                  Increase / (Decrease)                Percentage
Regulated Natural Gas (DTH)
 Residential and Commercial              6,419,031                 6,901,181                    (482,150)                                 (7) %
 Transportation and
Interruptible                            3,938,143                 2,975,312                     962,831                                  32  %
 Total Delivered Volumes                10,357,174                 9,876,493                     480,681                                   5  %
Heating Degree Days (Unofficial)             3,623                     3,791                        (168)                                 (4) %



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.
                                       19
--------------------------------------------------------------------------------


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

                                                                                      Increase /
Year Ended September 30,                    2020                  2019                (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 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:
                                      Years Ended September 30,
                                       2020               2019          Increase / (Decrease)
 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)
 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.
                                       20
--------------------------------------------------------------------------------

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. 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. 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. Basic and diluted earnings per share were $1.30
in fiscal 2020 compared to $1.08 in fiscal 2019. Dividends declared per share of
common stock were $0.70 in fiscal 2020 compared to $0.66 in fiscal 2019.

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 primarily relies on its operating cash flows and availability
under short-term and long-term credit agreements.










                                       21

--------------------------------------------------------------------------------

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

                                      Years Ended

September 30,


                                                        2020

2019

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

                (30,721,011)

(42,830,005)


Net cash provided by financing activities             16,556,826

29,516,238

Increase (decrease) in cash and cash equivalents $ (1,340,282) $ 1,383,937

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 $1.9 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:


                                                  Years Ended September 30,
                                                                                             Increase
Cash Flows From Operating Activities:             2020                  2019                (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)
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
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
                                       22
--------------------------------------------------------------------------------

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, 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 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.
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 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
                                       23
--------------------------------------------------------------------------------

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).

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 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 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
                                       24
--------------------------------------------------------------------------------

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. 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.

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
                                       25
--------------------------------------------------------------------------------

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. 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.

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 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 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 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. The non-gas base rates used since the passage of the TCJA in December
2017 through December 2018 were derived from a 34% federal tax rate. 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,
                                       26
--------------------------------------------------------------------------------

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 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. 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



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-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
                                       27
--------------------------------------------------------------------------------

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 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 $1,041,518 and $1,236,384 as of September 30, 2020
and 2019, 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 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
                                       28
--------------------------------------------------------------------------------

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.

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 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 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 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. 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. The Company continued to retain a 30% investment in equities to provide
asset growth potential to offset the growth in pension liability related to
those employees continuing to accrue benefits. 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 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.




                                       29
--------------------------------------------------------------------------------

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

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)

Funded status - September 30, 2019 Pension Postretirement 


      Total
Benefit Obligation                     $ 35,550,987      $    18,030,399      $ 53,581,386
Fair value of assets                     33,586,671           13,082,610        46,669,281
Funded status                          $ (1,964,316)     $    (4,947,789)     $ (6,912,105)



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 5.50% 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, 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.


                                                                                                      Increase in
                                                                              Increase in          Projected Benefit
Actuarial Assumptions - Pension Plan            Change in Assumption          Pension Cost            Obligation
Discount rate                                                -0.25  %       $     161,000          $    1,728,000
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.
                                                                                   Increase in            Increase in Accumulated
                                                                                 Postretirement           Postretirement Benefit

Actuarial Assumptions - Postretirement Plan Change in Assumption 

       Benefit Cost                  Obligation
Discount rate                                                  -0.25  %       $           42,000          $            771,000
Rate of return on plan assets                                  -0.25  %                   32,000                              N/A
Medical claim cost increase                                     0.25  %                   85,000                       735,000



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, 2020
related to its three variable rate notes. See Note 7 to the consolidated
financial statements for additional information regarding the swaps.
                                       30

--------------------------------------------------------------------------------

© Edgar Online, source Glimpses