Forward-Looking Statements
This report contains forward-looking statements that relate to future
transactions, events or expectations. In addition, Resources may publish
forward-looking statements relating to such matters as anticipated financial
performance, business prospects, technological developments, new products,
research and development activities and similar matters. These statements are
based on management's current expectations and information available at the time
of such statements and are believed to be reasonable and are made in good faith.
The Private Securities Litigation Reform Act of 1995 provides a safe harbor for
forward-looking statements. In order to comply with the terms of the safe
harbor, the Company notes that a variety of factors could cause the Company's
actual results and experience to differ materially from the anticipated results
or other expectations expressed in the Company's forward-looking statements. The
risks and uncertainties that may affect the operations, performance, development
and results of the Company's business include, but are not limited to those set
forth in the following discussion and within Item 1A "Risk Factors" in the
Company's 2019 Annual Report on Form 10-K. All of these factors are difficult to
predict and many are beyond the Company's control. Accordingly, while the
Company believes its forward-looking statements to be reasonable, there can be
no assurance that they will approximate actual experience or that the
expectations derived from them will be realized. When used in the Company's
documents or news releases, the words, "anticipate," "believe," "intend,"
"plan," "estimate," "expect," "objective," "projection," "forecast," "budget,"
"assume," "indicate" or similar words or future or conditional verbs such as
"will," "would," "should," "can," "could" or "may" are intended to identify
forward-looking statements.
Forward-looking statements reflect the Company's current expectations only as of
the date they are made. The Company assumes no duty to update these statements
should expectations change or actual results differ from current expectations
except as required by applicable laws and regulations.
The three-month earnings presented herein should not be considered as reflective
of the Company's consolidated financial results for the fiscal year ending
September 30, 2020. The total revenues and margins realized during the first
three months reflect higher billings due to the weather sensitive nature of the
natural gas business.
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.
Resources also invests in the Mountain Valley Pipeline, an interstate pipeline
currently under construction, as a more than 1% participant through its
Midstream subsidiary in addition to providing certain unregulated services
through its Roanoke Gas subsidiary. The unregulated operations of Roanoke Gas
represent less than 2% of total revenues of Resources on an annual basis.
The Company's utility operations are regulated by the SCC, which oversees the
terms, conditions, and rates to be charged to customers for natural gas service,
safety standards, extension of service, accounting and depreciation. 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. The Company is also subject to other
regulations which are not necessarily industry specific.
Over 98% of the Company's annual 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
non-gas rates contained in its rate application for natural gas service rendered
to customers on or after January 1, 2019. These non-gas rates are subject to
refund pending audit, hearing and a final order issued by the SCC. Both the SCC
staff and the hearing examiner on the case have completed their work and issued
their reports in June and November, respectively. On January 24, 2020, the SCC
issued the final order on the general rate application, granting Roanoke Gas an
annualized increase in the non-gas base rates of $7.25 million. The order also
directed the Company to write-down $317,191 of ESAC assets that were not subject
to recovery under the final order. The Company has revised its rate refund
accrual as of December 31, 2019 to reflect the rate award and ESAC write-down.
The Company has designed non-gas

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rates to reflect the increased revenues and has submitted the new rates to the
SCC for approval. Such rates may be adjusted by the SCC staff, which could
result in minor changes to the rate refund reserve. The Company will continue to
record a rate refund until such time as the final non-gas rates are approved and
the refund to customers is completed.
In fiscal 2019, the Company completed the transition to the 21% federal
statutory income tax rate as a result of the TCJA that was signed into law in
December 2017. 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 in effect. For the three-month period ended December
31, 2018, the Company accrued a refund of approximately $524,000 related to
these excess revenues for the effect of the different federal income tax rates
on the non-gas billing rates. Beginning in January 2019, 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 rate
application, and began refunding the excess revenues associated with the change
in the tax rate. The refund of the excess revenues related to the reduction in
the federal income tax rate was completed in 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 variations in weather and
the cost of natural gas, the Company 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 increased infrastructure
investment. These mechanisms include the SAVE Rider, WNA, ICC revenue 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 utilizing
historical and proforma information, including investment in natural gas
facilities. Generally, investments related to extending service to new customers
are recovered through the non-gas base rates currently in place, while the
investment in replacing and upgrading existing infrastructure is not recoverable
until a formal rate application is filed and approved. The SAVE Plan and Rider
provides a mechanism through which the Company may recover on a prospective
basis the related depreciation and expenses and provides a return on rate base
for the related additional qualified capital investments until such time that a
formal rate application is filed. As the Company has made significant SAVE
qualified expenditures since the last non-gas base rate increase in 2013, SAVE
Plan revenues have continued to increase each year. With the filing of the
non-gas rate application, the SAVE Rider reset effective January 2019 as the
prior revenues associated with the qualified SAVE Plan infrastructure
investments were incorporated into the non-gas rates. Accordingly, SAVE Plan
revenues declined by approximately $1,027,000 for the three-month period ended
December 31, 2019 compared to the same period last year.
The WNA model reduces earnings volatility, related to weather variability in the
heating season, by providing the Company a level of earnings protection when
weather is warmer than normal and providing customers some price protection when
the weather is colder than normal. The WNA is based on a weather measurement
band around the most recent 30-year temperature average. Under the WNA, the
Company recovers from its customers the lost margin (excluding gas costs) from
the impact of weather that is warmer than normal or refunds the excess margin
earned for weather that is colder than normal. The WNA mechanism used by the
Company is based on a linear regression model that determines the value of a
single heating degree day. For the three months ended December 31, 2019, the
Company accrued approximately $167,000 in additional revenues under the WNA
model for weather that was 4% warmer than normal compared to a reduction in
revenue of approximately $157,000 for weather that was 3% colder than normal for
the same period last year. The WNA year runs from April 1 to March 31 each year.
Annually, following the end of the WNA year, customers are either billed for any
margin shortfall or credited for any excess margin collected during the WNA
year.
The Company also has an approved rate structure in place that mitigates the
impact of financing costs associated with 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. This ICC factor
applied to the cost of 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, the Company recognizes ICC revenues to offset higher
financing costs associated with higher inventory balances. Conversely, during
times of decreasing gas costs and lower inventory balances, the Company
recognizes less carrying cost revenue as financing costs are lower. In addition,
ICC revenues are impacted by the changes in the weighting of the components that
are used to determine the weighted-average cost of capital. Total ICC revenues
for the three months ended December 31, 2019 declined by approximately 14% from
the same periods last year due to

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a combination of lower average price of gas in storage balances and a reduction
in the ICC factor used in calculating these 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 base 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 a quarterly basis, or more frequently
if necessary, the Company files a PGA rate adjustment request with the SCC to
adjust the gas cost component of its tariff rates 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 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 those amounts are reflected in customer billings.
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 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 believes it has taken reasonable security measures 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 exposure that may result from a cyber
incident.
Results of Operations
Three Months Ended December 31, 2019:
Net income increased by $1,572,774 for the three months ended December 31, 2019,
compared to the same period last year. Quarterly performance improved
significantly due to the impact of the rate increase and the earnings on the MVP
investment, offsetting increases in operation and maintenance costs and interest
expense.
The tables below reflect operating revenues, volume activity and heating
degree-days.

                                          Three Months Ended December 31,
                                                                                 Increase /
                                               2019                2018          (Decrease)       Percentage
Operating Revenues
Gas Utility                             $      19,625,606     $ 21,036,581     $  (1,410,975 )        (7 )%
Non utility                                       159,847          180,166           (20,319 )       (11 )%
Total Operating Revenues                $      19,785,453     $ 21,216,747     $  (1,431,294 )        (7 )%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial                      2,249,256        2,366,074          (116,818 )        (5 )%
Transportation and Interruptible                  869,582          750,065           119,517          16  %
Total Delivered Volumes                         3,118,838        3,116,139             2,699           -  %
Heating Degree Days (Unofficial)                    1,440            1,560              (120 )        (8 )%


Total operating revenues for the three months ended December 31, 2019, compared
to the same period last year, declined due to a 35% reduction in the commodity
price of natural gas and reduced SAVE Plan revenue more than offsetting the net
non-gas rate increase. The average commodity price of natural gas for the
current quarter was $2.50 per decatherm compared to $3.85 per decatherm for the
same period last year. Low natural gas prices are expected to continue due to
abundant supplies, with futures prices for the remainder of the fiscal year
averaging between $1.90 and $2.20 a decatherm. In addition, SAVE Plan revenues
declined by $1,026,899 as the SAVE Rider reset January 1, 2019, and all
qualifying SAVE Plan investments were included in rate base used to derive the
new non-gas base rates. The prior year SAVE Plan revenues represented 5 years of
SAVE investment while current year revenues represent only one year of
qualifying investment. As noted 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. The new rates incorporated revenues related to SAVE Plan
activities through December 2018, as well as recovery of higher expenses and
non-SAVE infrastructure additions since the last rate application. Total
revenues have been adjusted by an estimate for refunds based on the SCC's final
order. Net residential and commercial volume deliveries declined by 116,818

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decatherms on weather that was 8% warmer than normal. After adjusting for WNA,
total residential and commercial volumes effectively increased by nearly 26,000
decatherms or more than 1%. In addition, the prior year included a reserve of
$523,881 associated with the estimated excess revenues billed to customers as a
result of the reduction in the corporate federal income tax rate. No such
reserve was recorded during the current quarter due to the implementation of new
non-gas base rates in January 2019. Non-utility revenue declined due to do lower
demand for services during the quarter.

The Company's operations are affected by the cost of natural gas, as reflected
in the condensed 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 operating income, the most comparable GAAP
financial measure, as an indicator of operating performance and is not
necessarily comparable to similarly titled measures reported by other companies.
Therefore, the following discussion of financial performance will reference
gross utility margin as part of the analysis of the results of operations.

                                          Three Months Ended December 31,
                                                                                 Increase /
                                               2019                2018          (Decrease)       Percentage
Gas Utility Margin
  Utility Revenues                      $      19,625,606     $ 21,036,581     $  (1,410,975 )        (7 )%
  Cost of Gas                                   8,177,806       11,906,459        (3,728,653 )       (31 )%
  Gas Utility Margin                    $      11,447,800     $  9,130,122     $   2,317,678          25  %


Gross utility margins increased from the same period last year primarily as a
result of the implementation of higher non-gas base rates effective January 1,
2019. The non-gas base rate increase, net of estimated refund, accounted for
more than $2,000,000 of the increase in margin through the customer base charge
and the volumetric component in addition to customer growth. SAVE Plan revenues
declined by $1,026,899 as all related SAVE investments were incorporated into
the new non-gas base rates. WNA margin increased by nearly $324,000 as weather
moved from colder than normal in the prior year to warmer than normal during the
current quarter. Furthermore, the prior year included a reserve for excess
revenues attributable to the reduction in income tax rates. The current year has
no such adjustment as the new non-gas rates incorporate the effect of lower
federal income tax rates.
When the Company filed its application for an increase in non-gas base rates,
approximately 80% of the increase was reflected in the customer base charge to
correspond with the fixed monthly billing under the SAVE Rider. The SCC staff
report on the rate application recommended that only 20% of the non-gas base
rate increase be allocated to customer base charge. The hearing examiner's
report and subsequent final order supported this position. As a result, in June
2019, the Company revised its rate refund assumptions to reflect a rate design
that would allocate 80% of the non-gas base rate increase to volumetric
component and 20% to the customer base charge component. This revision results
in an even greater level of earnings during the weather sensitive heating season
due to the increased allocation to the weather sensitive component of non-gas
rates and lower earnings in the non-heating season due to lower fixed rate
revenues.
The components of and the change in gas utility margin are summarized below:
                           Three Months Ended December 31,
                                 2019                  2018         Increase / (Decrease)
Customer Base Charge  $       3,580,749            $ 3,117,995     $             462,754
Carrying Cost                   155,907                181,635                   (25,728 )
SAVE Plan                       180,613              1,207,512                (1,026,899 )
Volumetric                    7,303,843              5,259,338                 2,044,505
WNA                             166,597               (157,334 )                 323,931
Other Gas Revenues               60,091                 44,857                    15,234
Excess Revenue Refund                 -               (523,881 )                 523,881
Total                 $      11,447,800            $ 9,130,122     $           2,317,678



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Operation and maintenance expenses increased by $395,471, or 11%, from the same
period last year related to the write-off of a portion of the ESAC regulatory
assets, amortization of the remaining regulatory assets and higher corporate
insurance costs, partially offset by higher capitalized overheads. Beginning in
January 2019, concurrent with the implementation of new non-gas rates, the
Company began amortizing certain regulatory assets for which recovery was
included in the rate application. A total of $129,000 was charged to expense
related to the amortization of these assets. In addition, the SCC issued their
final order on the Company's non-gas rate increase, which directed the Company
to write-down $317,000 of ESAC assets that were not subject to recovery in the
final order. Corporate insurance expense increased by $71,000 due to higher
premiums related to increased liability limits and higher deductible reserves.
Capitalized overheads increased by $85,000 primarily due to timing of LNG
production related to facility upgrades at the plant during the summer. The
remaining difference relates to a variety of small increases and decreases in
expenses.
The Company has plans to invest in several one-time maintenance projects during
the balance of the current fiscal year, which may result in a significant
increase in operation and maintenance expenses when compared to fiscal 2019.
General taxes increased by $35,348, or 7%, associated with higher property and
payroll taxes. Property taxes continue to increase corresponding to higher
utility property balances related to ongoing infrastructure replacement, system
reinforcements and customer growth.

Depreciation expense increased by $83,030, or 4%, on an increase in utility
plant investment.
Equity in earnings of unconsolidated affiliate increased by $531,037, or nearly
double last year, due to AFUDC related to the increased construction activity
and related investment in the MVP.
Other income (expense), net increased by $31,757 primarily due to the
non-service components of net periodic benefit costs per the requirements of ASC
715 as amended by ASU 2017-07, Compensation - Retirement Benefits, which
requires that components of net periodic benefit costs other than service cost
be presented outside of income from operations. Lower interest costs and higher
return on plan assets offset increased amortization of the actuarial loss. See
Note 11 - Employee Benefit Plans for a breakdown of the components of net
periodic benefit costs.
Interest expense increased by $268,403, or 33%, due to a 34% increase in total
average debt outstanding between quarters. The higher borrowing levels derived
from the ongoing investment in MVP and financing expenditures in support of
Roanoke Gas' capital budget, partially offset by a slight reduction in the
weighted average interest rate.
Roanoke Gas interest expense increased by $142,614 as total average debt
outstanding increased by $9,500,000 associated with the issuance of two separate
debt issuances offset by reductions in the line-of-credit balances. The average
interest rate increased from 3.69% to 3.72% between periods.
Midstream interest expense increased by $125,789 as total average debt
outstanding increased by $18,400,000 associated with cash investment in the MVP.
The average interest rate decreased from 3.61% to 3.17% due to the decline in
the variable interest rate on Midstream's credit facility and the entry into two
separate notes with swap rates at 3.24% and 3.14%.
Income tax expense increased by $539,374 corresponding to an increase in taxable
income. The effective tax rate was 23.7% and 22.4% for the three month periods
ended December 31, 2019 and 2018, respectively. Both periods included the
amortization of excess deferred taxes.
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 consolidated 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 management 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 derived and changes in the estimate are reasonably
likely to occur from period to period. The Company had recorded an estimate for
customer refunds related to the implementation of the new non-gas base rates
effective January 1, 2019. In January 2020, the Company received the final order
on the non-gas base rate application that defined the approved annual rate
increase. Management developed revised non-gas rates based on the amount of the
increase specified in the order; however, the actual rates approved could vary
and result in minor adjustments to the reserve.

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The Company adopted 2016-02, Leases,, and subsequent guidance and amendments
effective October 1, 2019. 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 Company has only one lease, and management determined that the $25,000
value of the lease obligation to not be at a level material enough to warrant
the the application of the guidance under the ASU. The Company does have
easements for rights-of-way for its distribution system; however, all related
costs associated with these have been paid in advance with no remaining
obligation.
There have been no other changes to the critical accounting policies as
reflected in the Company's Annual Report on Form 10-K for the year ended
September 30, 2019.
Asset Management
Roanoke Gas uses a third-party asset manager to manage its pipeline
transportation, storage rights and gas supply inventories and deliveries. In
return for being able to utilize the excess capacities of the transportation and
storage rights, the asset manager pays Roanoke Gas a monthly utilization fee. In
accordance with an SCC order issued in 2018, a portion of the utilization fee is
retained by the Company with the balance passed through to customers through
reduced gas costs.

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, a
FERC-regulated natural gas pipeline connecting Equitran's gathering and
transmission system in northern West Virginia to the Transco interstate pipeline
in south central Virginia.

On November 19, 2019, the Company's Board of Directors approved a pro-rata increase in its participation in MVP, which will result in an estimated additional investment of $1.6 million above the current $53 to $55 million estimate. As a result of this increased participation, Midstream's equity interest will increase from 1.00% to approximately 1.03% by the time the pipeline is placed in service.



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
an additional delivery source of natural gas into its distribution system.
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. A third pipeline would reduce the
impact from such an event. 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 the its certificated service
territory.

The MVP project is currently 90% complete. Activity on the MVP is limited this
time of year to maintaining the infrastructure currently in place and
restoration activities. The LLC is waiting on the reissuance of water crossing
permits that were rescinded by the Fourth Circuit as well as the permit to cross
a section of the Jefferson National Forest. The LLC believes it has submitted
all of the required documentation and information required to resolve the issues
addressed by the Fourth Circuit. Currently, no action has been taken by the
governmental agencies regarding the status, including the need for additional
information, re-approval of the permits or rejection of the submissions. Until
such time as approval is granted, activity on the pipeline will be limited as
most of the pipeline work not encompassed in the revoked permits has been
completed.

Assuming timely resolution of the permit issues above, the LLC projects an in-service date for the MVP in late calendar year 2020. The delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action that could provide for the recovery of these higher costs.



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. Under the amended agreement and notes, Midstream should have
the needed financing to meet its funding requirements in the MVP. If the
rescinded permits are not re-issued and approved in a reasonable time period,
both the cost of the MVP and Midstream's capital contributions will increase
above current estimates and the in-service date will be extended beyond 2020.

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
facility infrastructure are credited to income and charged to the cost of the
project. The level of investment in MVP, as well as the AFUDC, will continue to
grow as construction activities continue. When the pipeline is completed and
placed into service, AFUDC will cease. Once operational, earnings will be

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derived from capacity charges for utilizing the pipeline. Continued delays in
the project could ultimately result in future earnings from the operation of the
pipeline to be below the level of AFUDC recognized.

In 2018, Midstream became a participant in Southgate, a project to construct a
74-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 project cost estimates,
will invest approximately $2.5 million in the project. Midstream's participation
in the Southgate project is for investment purposes only. The Southgate
in-service date is currently targeted for 2021.

Regulatory and Tax Reform



On October 10, 2018, Roanoke Gas filed a general rate case application
requesting an annual increase in customer non-gas base rates of approximately
$10.5 million. This application incorporated into the non-gas base rates the
impact of tax reform, non-SAVE utility plant investment, increased operating
costs, recovery of regulatory assets, including all deferred ESAC related costs,
and SAVE Plan investments and related costs previously recovered through the
SAVE Rider. Approximately $4.7 million of the rate increase was attributable to
moving the SAVE Plan related revenues into non-gas base rates. The new non-gas
base rates were placed into effect for gas service rendered on or after January
1, 2019, subject to refund, pending audit by SCC staff, hearing and final order
by the SCC.

On June 28, 2019, the SCC staff issued their report and recommendations related
to the rate application. The SCC staff report included a recommendation for a
non-gas rate increase of approximately $6.5 million. Management reviewed and
responded to the SCC staff report through submission of rebuttal testimony to
certain proposed adjustments included in the report. At the hearing held on
August 14 and 15, the Company addressed specific differences with SCC staff,
including the proposed return on equity, the exclusion of certain infrastructure
items from rate base, changes in customer class rate design and the exclusion of
a portion of the regulatory assets associated with ESAC costs. On November 19,
2019, the hearing examiner issued his report, which was subsequently revised on
November 26, 2019. The revised report recommended an annual increase in non-gas
base rates of more than $7.1 million in addition to allocating 80% of the
increase to the volumetric component of rates with only about 20% associated
with customer base charges. On January 24, 2020, the SCC issued their final
order providing for an annual increase in non-gas base rates of $7.25 million,
while maintaining the allocation of 80% of the increase to the volumetric
component of rates. The non-gas rate award provided for a 9.44% return on
equity, but excluded from recovery 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 the ESAC assets that were
excluded from recovery under the rate award. As a result, the Company expensed
an additional $317,000 of ESAC assets above the normal amortization amount.
Management has proposed a rate design to reflect the increase of $7.25 million
in non-gas rates and has submitted these rates to the SCC for approval. The SCC
may approve the rates as submitted or require changes to the rates, which could
result in minor adjustments to the refund. Once the final rates have been
approved, the Company will proceed with completing the refunds to its customers.
Management has provided for a cumulative refund in the amount of $3,618,000
consistent with the SCC order based on the non-gas rates that are currently
pending approval. The refund accrual will cease once the approved rates are
placed into effect.

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 corresponding balances related to the excess deferred taxes are included in
the regulatory liability schedule in Note 14.

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, Roanoke Gas
recorded 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.


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RGC RESOURCES, INC. AND SUBSIDIARIES




The Company continues to recover the costs of its infrastructure replacement
program through its SAVE Plan. The original SAVE Plan was designed to facilitate
the accelerated replacement of aging natural gas pipe by providing a mechanism
for the Company to recover the related depreciation and expenses and return on
rate base of the additional capital investment without the filing of a non-gas
base rate application. Since the implementation and approval of the original
SAVE Plan in 2012, the Company has modified, amended or updated it each year to
incorporate various qualifying projects. In May 2019, the Company filed its most
recent SAVE Plan and Rider, which continues the focus on the ongoing replacement
of pre-1973 plastic pipe and the replacement of a natural gas transfer station.
In September 2019, the SCC approved the updated SAVE Plan and Rider effective
with the October 2019 billing cycle. The new SAVE Rider is designed to collect
approximately $1.1 million in annual revenues, an increase from the approximate
$500,000 in annual revenues under the prior SAVE rates. With the inclusion of
all previous SAVE investment through December 31, 2018 into the rate
application, the current SAVE Plan Rider reflects only the recovery of
qualifying SAVE Plan investments made since the beginning of January 2019. In
addition, the SAVE application includes a refund factor to return approximately
$543,000 in SAVE revenue over-collections from 2018, primarily resulting from
the effect of the reduction in the federal income tax rate.
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 utility plant capital projects, investment in the MVP, the seasonal
funding of its natural gas inventories and accounts receivable and the payment
of dividends. To meet these needs, the Company relies on its operating cash
flows, line-of-credit agreement, long-term debt and equity capital.
Cash and cash equivalents decreased by $619,001 for the three-month period ended
December 31, 2019, compared to a $236,602 decrease for the same period last
year. The following table summarizes the sources and uses of cash:

                                                               Three Months Ended December 31,
                                                                 2019                  2018
Cash Flow Summary
Net cash provided by (used in) operating activities        $      817,963       $      (2,300,174 )
Net cash used in investing activities                         (10,875,736 )           (15,833,528 )
Net cash provided by financing activities                       9,438,772              17,897,100
Decrease in cash and cash equivalents                      $     (619,001 )

$ (236,602 )




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, contribute to working capital levels and the related cash flows.
Generally, operating cash flows are positive during the second and third
quarters as a combination of earnings, declining storage gas levels and
collections on customer accounts all contribute to higher cash levels. During
the first and fourth quarters, operating cash flows generally decrease due to
increases in natural gas storage levels, rising customer receivable balances and
construction activity.
Cash flow provided by operations is primarily driven by net income,
depreciation, reductions in natural gas storage inventory and increases in
accounts receivable during the first three months of the fiscal year. Cash flow
from operating activities increased by $3,118,137 over the same period last year
primarily related to higher net income, net of equity in earnings, and the
effect of lower natural gas prices on accounts receivable, gas in storage and
accounts payable. Net income, excluding the non cash component of equity in
earnings, contributed more than $1.0 million to the increase in cash provided by
operations primarily as a result of the implementation of the non-gas base rate
increase. However, significantly lower natural gas commodity prices have
resulted in a reduced customer volumetric billing rate and lower total customer
billings during the period more than offsetting the impact of the non-gas base
rate increase. These lower commodity prices have resulted in smaller increases
in both accounts receivable and accounts payable and their corresponding effect
on operating cash. The decline in gas in storage was less during the current
fiscal quarter compared to the same period last year due to a combination of
lower average cost of gas in storage and less natural gas withdrawn from
storage. A summary of the cash provided by operations is provided below:

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