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MarketScreener Homepage  >  Equities  >  Nasdaq  >  RGC Resources, Inc.    RGCO

RGC RESOURCES, INC.

(RGCO)
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RGC RESOURCES : Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-K)

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12/03/2019 | 02:13pm EST

Overview


Resources is an energy services company primarily engaged in the regulated sale
and distribution of natural gas to approximately 60,700 residential, commercial
and industrial customers in Roanoke, Virginia, and the surrounding localities,
through its Roanoke Gas subsidiary. Roanoke Gas also provides certain
unregulated services. As a wholly-owned subsidiary of Resources, Midstream is a
1% member in the Mountain Valley Pipeline, LLC. More information regarding the
investment in MVP is provided under the Equity Investment in Mountain Valley
Pipeline section below. The unregulated operations represent less than 2% of
revenues and margins of Resources.

The utility operations of Roanoke Gas are regulated by the SCC, which oversees
the terms, conditions, and rates to be charged to customers for natural gas
service, safety standards, extension of service, accounting and depreciation.
Roanoke Gas is also subject to federal regulation from the Department of
Transportation in regard to the construction, operation, maintenance, safety and
integrity of its transmission and distribution pipelines. FERC regulates prices
for the transportation and delivery of natural gas to the Company's distribution
system and underground storage services. Roanoke Gas is also subject to other
regulations which are not necessarily industry specific.

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.

The Company has completed the transition to the 21% federal statutory income tax
rate as a result of the TCJA that was signed into law in December 2017. Since
the implementation of the new tax rates, the Company has recorded a provision
for refund related to estimated excess revenues collected from customers under
approved billing rates designed to recover expenses and provide a rate of return
based on a federal tax rate of 34%. Beginning January 1, 2019, Roanoke Gas
incorporated the effect of the 21% federal tax rate with the implementation of
new non-gas base rates, as filed in its current rate application, and began
refunding the excess revenues associated with the change in the tax rate over
the subsequent 12-month period. 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

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refunded to customers over a 28-year period. The SCC staff report issued, as
part of the audit of the Company's non-gas rate application, indicated no
changes to the amounts for excess revenue collected and the excess deferred
taxes to be refunded to customers. The Company expects to complete the refund of
the excess revenues by December and will continue to refund the excess deferred
taxes over time. Additional information regarding the TCJA and non-gas base rate
application is provided under the Regulatory and Tax Reform section below.

As mentioned above, the Company currently has a non-gas base rate application
pending before the SCC. Roanoke Gas implemented the non-gas rates contained in
its rate application for natural gas service rendered to customers on or after
January 1, 2019. These non-gas rates are subject to refund pending audit,
hearing and a final order issued by the SCC. On June 28, 2019, the SCC staff
issued its report and findings from the audit of the rate application. In its
report, the SCC staff recommended a lower non-gas base rate increase than was
requested in the rate application, which is normal and expected. In addition,
the SCC staff recommended a change in rate design between customer base charge
and volumetric rates, shifting much of the increase in non-gas base rates from
customer base charges to the volumetric components. At the hearing held in
August 2019, management provided additional testimony and rebuttal to certain
proposed adjustments in response to the SCC staff report. After evaluating the
adjustments proposed by the SCC staff and the testimony provided at the hearing,
management updated its assumptions used in estimating the refund amount included
in the financial statements. The hearing examiner's report and final order from
the SCC is not expected until December 2019 or early 2020. Upon receipt of the
final order, the Company will adjust the interim rates to the those approved in
the rate order and finalize the rate refund based on the approved rates.
Subsequent to year end, the Company received the hearing examiner's reports. See
Note 15 and the Regulatory and Tax Reform section below for additional
information.

The Company is committed to the safe and reliable delivery of natural gas to its
customers. Since 1991, the Company has placed an emphasis on the modernization
of its distribution system through the renewal and replacement of its cast iron
and bare steel natural gas distribution pipelines and other system improvements.
In 2017, the Company completed the replacement of all cast iron and bare steel
pipe and is continuing its renewal program with other qualified infrastructure
replacement programs including the renewal of first generation, pre-1973 plastic
pipe.

The Company is also dedicated to the safeguarding of its information technology
systems.  These systems contain confidential customer, vendor and employee
information as well as important financial data.  There is risk associated with
the unauthorized access of this information with a malicious intent to corrupt
data, cause operational disruptions, or compromise information.  Management
believes it has taken reasonable security measures to protect these systems from
cyber attacks and other types of incidents; however, there can be no guarantee
that an incident will not occur.  In the event of a cyber incident, the Company
will execute its Security Incident Response Plan.  The Company maintains
cyber-insurance coverage to mitigate financial expense that may result from a
cyber incident.

As the Company's business is seasonal in nature, volatility in winter weather
and the commodity price of natural gas, can impact the effectiveness of the
Company's rates in recovering its costs and providing a reasonable return for
its shareholders. In order to mitigate the effect of weather variations and
other factors not provided for in the Company's base rates, Roanoke Gas has
certain approved rate mechanisms in place that help provide stability in
earnings, adjust for volatility in the price of natural gas and provide a return
on qualified infrastructure investment. These mechanisms include the SAVE Rider,
WNA, ICC revenue and PGA.

The Company's non-gas base rates are designed to allow for the recovery of
non-gas related expenses and provide a reasonable return to shareholders. These
rates are determined based on the filing of a formal rate application with the
SCC. 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 until such time a formal rate application is filed to incorporate
this investment in the Company's non-gas base rates. Since the Company's
previous non-gas base rate application in 2013, SAVE Plan revenues have grown
each year corresponding to the level of SAVE qualifying capital investment. With
the filing of the new non-gas base rate application, the SAVE Rider has been
reset as the qualified SAVE Plan investment through December 2018 has been
incorporated into the current application. Accordingly, SAVE Plan revenues
declined to $1,599,000 in fiscal 2019 compared to $4,469,000 and $3,813,000 for
fiscal 2018 and 2017. Additional information regarding the SAVE Rider is
provided under the Regulatory Affairs section.

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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 the
WNA year end, which runs from April to March. For the fiscal year ended
September 30, 2019, the Company recorded approximately $453,000 in additional
revenue from the WNA for weather that was approximately 4% warmer than normal.
For the fiscal years ended September 30, 2018 and 2017, the Company recorded
$45,000 and $1,839,000 in additional revenue from the WNA for weather that was
approximately 1% and 18% warmer than normal, respectively. As normal weather is
based on the most recent 30-year temperature average, the number of heating
degree days used to determine normal will change annually as a new year is added
to the 30-year period and the oldest year is removed. As a result of adding
recent warmer than normal years to replace colder historical years to the
30-year period, the number of heating degree days that defines normal has
declined from 3,998 in fiscal 2013 to 3,925 in fiscal 2019. The Company's prior
rates were designed on 4,000 heating degree days based on its last non-gas rate
filing; however, the 2019 WNA model is recovering based on 3,949 heating degree
days, or about 1% less than what the prior non-gas rates were designed to
recover. The 30-year normal has been reset to 3,959 in the determination of the
new non-gas base rates in the current rate application.

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 10% reduction in the
average cost of gas in storage during fiscal 2019 and a 5% reduction in the ICC
factor, resulted in a decline in ICC revenues of approximately $92,000 from
fiscal 2018. This compares to a decline of $35,000 in ICC revenues for fiscal
2018 compared to fiscal 2017. Based on current storage balances and natural gas
futures, the average dollar balance of gas in storage should remain stable and,
with a more consistent ICC factor, should result in less volatility in ICC
revenues.

The Company's approved billing rates include a component designed to allow for
the recovery of the cost of natural gas used by its customers. The cost of
natural gas is considered a pass-through cost and is independent of the non-gas
rates of the Company. 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.

The economic environment has a direct correlation with business and industrial
production, customer growth and natural gas utilization. Currently, the local
economy continues to show modest growth and should continue to improve absent a
major economic setback on a local, regional or national level.

Results of Operations


The analysis on the results of operations is based on the consolidated
operations of the Company, which is primarily associated with the utility
segment. Additional segment analysis is provided in areas where the investment
in affiliates segment (investment in MVP and Southgate) represent a significant
component of the expense comparison.


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Fiscal Year 2019 Compared with Fiscal Year 2018


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

Operating Revenues
                                                                  Increase /
Year Ended September 30,       2019               2018           
(Decrease)          Percentage
Gas Utilities            $   67,306,260$   64,341,783$     2,964,477                5  %
Other                           720,265          1,192,953            (472,688 )            (40 )%
Total Operating Revenues $   68,026,525$   65,534,736$     2,491,789                4  %



Delivered Volumes
Year Ended September                                         Increase /
30,                          2019             2018           (Decrease)          Percentage
Regulated Natural Gas
(DTH)
 Residential and
Commercial                 6,901,181        7,103,825         (202,644 )               (3 )%
 Transportation and
Interruptible              2,975,312        2,822,149          153,163                  5  %
 Total Delivered
Volumes                    9,876,493        9,925,974          (49,481 )                -  %
Heating Degree Days
(Unofficial)                   3,791            3,954             (163 )               (4 )%



Total gas utility operating revenues for the year ended September 30, 2019
increased by 5% from the year ended September 30, 2018 primarily due to the
implementation of higher non-gas rates and slightly higher gas costs. The
Company implemented new non-gas base rates effective for natural gas service
rendered on or after January 1, 2019, subject to refund. The revenues have been
reduced by management's estimate of a rate refund pending final resolution of
the rate application and order by the SCC. Total natural gas deliveries
decreased by less than 1% from last year primarily due to warmer weather, offset
by increased industrial consumption. Industrial consumption, as reflected in the
transportation and interruptible volumes, increased due to a significant
increase in usage by one customer and a large commercial customer that
transferred to firm transportation during fiscal 2019. Residential and
commercial customers' natural gas usage tends to be more weather sensitive as
reflected by a 3% decline in volumes on 4% fewer heating degree days. After
adjusting for WNA and the transfer of the large commercial customer to firm
transportation, total residential and commercial volumes reflect an increase of
more than 1%. The average commodity price of natural gas delivered during fiscal
2019 was approximately 4% per decatherm higher than for fiscal 2018. Natural gas
commodity prices spiked during December 2018 due to weather, but have since
returned to lower levels. The prior year included a reserve of $1,320,167
associated with the accumulated excess revenues billed to customers as a result
of the reduction in the corporate federal income tax rate. The current fiscal
year includes a reserve of $523,881 as the accrual for excess revenues ended
with the implementation of new non-gas rates, which incorporated the reduction
in the federal income tax rate. Other revenues decreased by 40% due to a
significant reduction in services during the last half of the year.

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 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.


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Gross Utility Margin


Year Ended September 30,     2019            2018          Increase     Percentage
Utility revenues         $ 67,306,260$ 64,341,783$ 2,964,477        5 %
Cost of gas                32,401,123      32,091,923        309,200        1 %
Gross Utility Margin     $ 34,905,137$ 32,249,860$ 2,655,277        8 %



Gross utility margins increased over last year primarily as a result of
implementing higher non-gas base rates effective January 1, 2019. SAVE Plan
revenues declined by nearly $2,900,000 as all related SAVE investment through
December 31, 2018 was incorporated into the new non-gas base rates. As noted
above, the SCC staff recommended a change in the proposed rate design of the
non-gas rate increase between customer base charge and volumetric rates. In
designing the rates submitted in the rate application, the Company included SAVE
related revenues in the base charge component as the SAVE rider was previously
reflected as a fixed fee on customers bills. As a result, the new rates
implemented in January 2019 included a much larger allocation of the rate
increase to the customer base charge. The SCC staff recommended in their report
to significantly reduce the customer base charge rate and move it to the
volumetric component of non-gas rates. Due to the staff's position and the
results of non-gas rate applications from other Virginia utilities, the Company
incorporated into its rate refund assumptions a significant reduction in
customer base charge revenue and an increase in volumetric revenue. As a result,
the net impact of the rate increase incorporating the rate refund assumptions
resulted in an increase in the customer base charge of $1,009,479 and an
increase in the volumetric margin of $3,409,095. As noted above, WNA revenues
were higher due to warmer weather, while excess revenues related to tax reform
were lower during the current year as new non-gas rates were implemented that
incorporated the effects of the TCJA.

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

                                Years Ended September 30,
                                  2019             2018         Increase / (Decrease)
Customer Base Charge         $ 13,486,234$ 12,476,755     $           1,009,479
SAVE Plan                       1,599,281        4,468,556                (2,869,275 )
Volumetric                     19,298,454       15,889,359                 3,409,095
WNA                               452,892           44,569                   408,323
Carrying Cost                     462,260          554,090                   (91,830 )
Excess Revenues - Tax Reform     (523,881 )     (1,320,167 )                 796,286
Other Revenues                    129,897          136,698                    (6,801 )
Total                        $ 34,905,137$ 32,249,860     $           2,655,277



Operations and Maintenance Expense - Operations and maintenance expense
increased by $1,617,591, or 13%, from last year primarily due to higher
compensation costs, amortization of regulatory assets, corporate insurance
costs, lower capitalized overheads, maintenance activities and higher bad debt
expense. Total compensation costs increased by $647,000 due to higher staffing
levels in regulatory and operations support combined with wage increases.
Beginning in January 2019, concurrent with the implementation of new non-gas
rates, the Company began amortizing certain regulatory assets for which recovery
was included in the rate application. A total of $372,000 was charged to expense
related to the amortization of these assets. Most of the regulatory assets have
a 5-year amortization period. Corporate insurance expense increased by $125,000
due to higher premiums related to increased liability limits and higher
deductible reserves. Capitalized overheads declined by $255,000 due to lower
overall capital expenditures and reduced LNG production related to timing of
facility upgrades at the plant. Contracted maintenance related to work on the
LNG plant and brush clearing along the Company's transmission right of way
increased maintenance costs by $186,000. Bad debt expense increased by $55,000
associated with increased customer billings.

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



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


Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the
MVP investment increased by $2,081,817 due to AFUDC related to increased
investment in the project. Total cash investment in fiscal 2019 was nearly $21
million. The investment in Mountain Valley Pipeline and the related AFUDC
earnings are discussed further under the Equity Investment in Mountain Valley
Pipeline section below.

Other Income (Expense), net - Other income increased by $107,014 primarily due
to a full year of revenue sharing received by the Company under the gas supply
asset management agreement and the adoption of ASU 2017-07. Revenue sharing fees
increased by $313,000 as the incentive mechanism was only in effect for a
portion of last year. ASU 2017-07 requires that net periodic benefit costs,
other than service cost, be presented outside of income from operations. As a
result of the adoption of this ASU, the prior years financial statements have
been adjusted retrospectively with the reclassification of $123,000 in net
expense reduction from operations and maintenance to other income for fiscal
2018. Current year net expense reductions related to other benefit costs were
less than $2,000. The remaining difference is attributable to pipeline
assessments and charitable contributions. See the Regulatory and Tax Reform
section below for more information on revenue sharing and Note 1 for information
on the adoption of ASU 2017-07.

Interest Expense - Total interest expense increased by $1,156,986, or 47%, due
to a 41% increase in the average total debt outstanding during the year
attributed to the investment in MVP and financing expenditures in support of
Roanoke Gas' capital budget. The Company contributed nearly $21 million to its
investment in MVP during the year as Midstream's borrowing increased by more
than $22 million with a corresponding increase in interest expense of $832,000.
Roanoke Gas' total borrowing increased by more than $10 million related to the
issuance of an unsecured note to refinance a portion of the line-of-credit,
which accounted for the remaining increase in interest expense. The average
interest rate on consolidated borrowings increased during the current year from
3.80% to 3.92%.

Income Taxes - Income tax expense decreased by $244,405, or 8%, even though
pre-tax earnings increased. The effective tax rate was 23.4% for fiscal 2019
compared to 28.4% for fiscal 2018. These decreases in the effective tax rate and
income tax expense correspond to the reduction in the corporate federal income
tax rate from the 24.3% blended federal tax rate in fiscal 2018 to the 21%
statutory rate in fiscal 2019. Fiscal 2018 income tax expense also included
$256,444 of additional tax expense for the revaluation of net deferred tax
assets of the unregulated operations to the 21% federal tax rate. Income tax
expense related to the MVP investment increased by $359,000 due to the
significant growth in pre-tax earnings. Additional information regarding the
impact of tax reform can be found in Note 8 and under the Regulatory and Tax
Reform section below.

Net Income and Dividends - Net income for fiscal 2019 was $8,698,412 compared to
$7,297,205 for fiscal 2018. Basic and diluted earnings per share were $1.08 in
fiscal 2019 compared to $0.95 in fiscal 2018. Dividends declared per share of
common stock were $0.66 in fiscal 2019 compared to $0.62 in fiscal 2018.

Fiscal Year 2018 Compared with Fiscal Year 2017


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

Operating Revenues

Year Ended September 30,     2018            2017          Increase      Percentage
Gas Utilities            $ 64,341,783$ 61,252,015$ 3,089,768          5 %
Other                       1,192,953       1,044,855        148,098         14 %
Total Operating Revenues $ 65,534,736$ 62,296,870$ 3,237,866          5 %




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Delivered Volumes

Year Ended September 30,             2018         2017       Increase     Percentage
Regulated Natural Gas (DTH)
 Residential and Commercial       7,103,825    5,840,883    1,262,942         22 %

Transportation and Interruptible 2,822,149 2,721,699 100,450

4 %

Total Delivered Volumes 9,925,974 8,562,582 1,363,392

   16 %
Heating Degree Days (Unofficial)      3,954        3,250          704       

22 %




Total gas utility operating revenues for the year ended September 30, 2018
increased by 5% from the year ended September 30, 2017 primarily due to higher
gas sales and increased SAVE Plan revenues more than offsetting refunds related
to the reduction in the corporate federal income tax rate and lower gas costs.
Total natural gas deliveries increased by 16% over fiscal 2017 primarily due to
weather and increased commercial and industrial consumption. Industrial
consumption, as reflected in the transportation and interruptible volumes,
increased as net production activities increased due to a stronger local
economy. Residential and commercial volumes increased by 22% on a corresponding
22% increase in heating degree days. Usage by larger commercial customers, which
generally are less weather sensitive than residential and smaller commercial
customers, increased by 20% due to a combination of colder weather, new business
development in the region and increased usage by existing customers. SAVE Plan
revenues grew by 17% due to the Company's ongoing investment in its SAVE related
infrastructure replacement program. The Company also recorded a reserve in the
amount of $1,320,167 associated with the accumulated excess revenues billed to
customers as a result of the reduction in the corporate federal income tax rate.
Other revenues increased by 14% due to increased customer requirements.

Gross Utility Margin

                                                                  Increase /
Year Ended September 30,       2018               2017           
(Decrease)          Percentage
Utility revenues         $   64,341,783$   61,252,015$     3,089,768                5 %
Cost of gas                  32,091,923         28,919,625           3,172,298               11 %

Gross Utility Margin $ 32,249,860$ 32,332,390$ (82,530 )

              - %



Gross utility margins were nearly unchanged from fiscal 2017, as higher SAVE
Plan revenues and increased volume deliveries were offset by the excess revenue
reserve adjustment to refund customers for the effects of the lower federal
income tax rate. Total SAVE Plan revenues increased by $656,000 as the Company
continues to invest in qualified infrastructure projects. Since January 2014,
the Company had invested nearly $40,000,000 in such projects. Volumetric margin
increased by nearly $2,316,000 due to greater natural gas deliveries resulting
from much colder weather and growth in both customers and non-weather related
customer usage. Much of the margin related to increased sales was offset by a
much lower WNA adjustment. Weather during fiscal 2018 was nearly normal while
the weather in fiscal 2017 was 18% warmer than normal resulting in a reduction
in the WNA adjustment of $1,795,000. The remaining net increase in WNA adjusted
margin is related to increased economic activity in the region combined with
customer growth. ICC revenues declined by $35,000 due to a lower ICC factor.

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




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                        Years Ended September 30,
                          2018             2017         Increase / (Decrease)
Customer Base Charge $  12,476,755$ 12,412,753    $              64,002
SAVE Plan                4,468,556        3,813,043                  655,513
Volumetric              15,889,359       13,573,704                2,315,655
WNA                         44,569        1,839,454               (1,794,885 )
Carrying Cost              554,090          588,624                  (34,534 )
Rate Refund             (1,320,167 )              -               (1,320,167 )
Other Revenues             136,698          104,812                   31,886
Total                $  32,249,860$ 32,332,390    $             (82,530 )



Operations and Maintenance Expense - Operations and maintenance expense
decreased by $102,180, or 1%, from fiscal 2017 primarily due to reductions in
compensation costs, contracted services and benefit costs partially offset by
the reclassification of net periodic benefit costs other than service cost from
operating and maintenance expense to non-operating expense and higher bad debt
expense. Compensation declined by $127,000 in large part due to the reduction in
employees related to the outsourcing of the customer service function, net of
additions in other areas. Contracted services also declined as the higher costs
related to outsourcing the customer service function were offset by declines in
meter reading costs, due to the implementation of an automated meter reading
system in fiscal 2017, and the insourcing of the utility line locating function.
Employee benefit costs declined by $705,000 primarily as a result of decreases
in the actuarially determined expenses of both the pension and other
post-retirement benefit plans. Strong asset performance and funding combined
with an increase in the discount rate served to reduce the actuarially
determined expenses of the plans and improve the overall funded status. Bad debt
expense increased by $85,000 on higher gross customer billings due to a much
colder heating season compared to the prior year. Operating and maintenance
expense has been revised for fiscal 2018 and 2017 due to the adoption of ASU
2017-07 related to the change in financial presentation of other net periodic
benefit costs. As a result of this reclassification, operation and maintenance
expense increased by $648,971, while at the same time other income (expense),
net increased by the same amount. See Note 1 for more information regarding the
ASU 2017-07.

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

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

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


Other Income (Expense), net - Other income (expense) moved from $658,879 in net
other expense to $224,868 in net other income primarily due to the
reclassification of other net periodic benefit costs out of operation and
maintenance expense into other income (expense) as required under ASU 2017-07.
The reclassification accounted for $648,971 of the change with most of the
remaining difference resulting from the implementation of the revenue sharing
incentive mechanism, lower pipeline assessments and charitable commitments and
higher interest earnings. See Note 1 for additional information regarding ASU
2017-07.

Interest Expense - Total interest expense increased by $544,311, or 28%, due to
a 20% increase in the average total debt outstanding during the year. Most of
the net increase in borrowing is attributable to the investment in Mountain
Valley Pipeline, which accounted for $244,000 of the increase in interest
expense. Roanoke Gas funded its capital expenditures for 2018 through the $15
million equity infusion from Resources. The average interest rate increased
during the current year from 3.56% to 3.80%. The increase in the average
interest rate is due to the issuance of the $8,000,000 unsecured notes on
October 2, 2017 at a rate of 3.58% which replaced a portion of the lower-rate
balance under the line-of-credit combined with the rising interest rate on the
Company's variable-rate debt.

Income Taxes - Income tax expense decreased by $910,254, or 24%, even though
pre-tax earnings increased. The effective tax rate was 28.4% for fiscal 2018
compared to 37.9% for fiscal 2017. This decrease in the effective tax rate and
income tax expense corresponds to the reduction in the corporate federal income
tax rate from 34% for fiscal 2017

                                       23
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to a 24.3% blended rate for fiscal 2018, and ultimately to 21% in fiscal 2019. Income tax expense related to the MVP investment was nearly unchanged as a reduced federal income tax rate offset growth in pre-tax earnings.


Net Income and Dividends - Net income for fiscal 2018 was $7,297,205 compared to
$6,232,865 for fiscal 2017. Basic and diluted earnings per share were $0.95 in
fiscal 2018 compared to $0.86 in fiscal 2017. Dividends declared per share of
common stock were $0.62 in fiscal 2018 compared to $0.58 in fiscal 2017.

Capital Resources and Liquidity


Due to the capital intensive nature of the utility business, as well as the
related weather sensitivity, the Company's primary capital needs are for the
funding of its continuing construction program, the seasonal funding of its
natural gas inventories and accounts receivables and payment of dividends. To
meet these needs, the Company relies on its operating cash flows, line-of-credit
agreement, long-term debt and capital raised through the issuance of common
stock.

Cash and cash equivalents increased by $1,383,937 in fiscal 2019 compared to an
increase of $177,771 in fiscal 2018 and a decrease of $573,612 in fiscal 2017.
The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary                                    Year Ended September 

30,

                                             2019              2018         

2017

Net cash provided by operating
activities                              $  14,697,704$  13,503,795$  12,980,978
Net cash used in investing activities     (42,830,005 )     (34,166,578 )     (23,492,555 )
Net cash provided by financing
activities                                 29,516,238        20,840,554     

9,937,965

Increase (decrease) in cash and cash
equivalents                             $   1,383,937$     177,771$    (573,612 )

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
quarters as a combination of earnings, declining storage gas levels and
collections on customer accounts all contribute to higher cash levels. During
the first and fourth quarters, operating cash flows generally decrease due to
the combination of increasing natural gas storage levels and rising customer
receivable balances.

Cash provided by operating activities was approximately $14,698,000 in fiscal
2019, $13,504,000 in fiscal 2018 and $12,981,000 in fiscal 2017. Cash provided
by operating activities increased by nearly $1.2 million over last year
primarily as the net result of several items including net income, depreciation,
estimated provision for rate refund, gas in storage and change in over/under
collection of gas costs, offset by equity in earnings and additional pension
funding. Although net income increased by $1.4 million, most of the earnings
growth derived from the non-cash $2.1 million growth in equity in earnings on
the investment in MVP. Increased depreciation contributed more than $500,000 in
additional operating cash, related to the increasing investment in natural gas
infrastructure. The combination of lower commodity prices during the summer
injection period and lower storage levels contributed $1.1 million in additional
cash over last year. The net rate refund estimate increased by $1.2 million due
to the collection of revenues in excess of management's estimate of the final
rate award related to the non-gas base rate application, net of the partial
refunding of the excess tax revenues collected in rates prior to the
implementation of the new non-gas rates in January 2019. Over-collections of gas
cost increased by more than $3.4 million over the same period last year. Natural
gas prices spiked in December and futures prices at the time indicated that
natural gas commodity prices would remain at an elevated level during the winter
months. Based on this information, the Company filed its quarterly PGA
adjustment reflecting higher prices; however, commodity prices quickly declined
to levels below the prior year during the second and third fiscal quarters
resulting in the move to an over-collected position. A $1.2 million decrease in
cash resulted from the change in prepaid income taxes, as adjustments were made
in the prior year to reduce estimated tax payments as a result of TCJA. Accounts
payable and accrued expenses used an additional $2.9 million due to reduction in
accounts payable balances associated with lower gas costs and additional funding
provided to the pension plan as reflected in Note 9. The table below summarizes
the significant operating cash flow components:

                                       24
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                                               Years Ended September 30,
Cash Flows From Operating Activities:           2019               2018          Increase (Decrease)
Net Income                                $    8,698,412$    7,297,205     $         1,401,207
Depreciation                                   7,600,852          7,090,169                 510,683
Equity in earnings                            (3,020,348 )         (938,531 )            (2,081,817 )
Gas in storage                                 1,178,889             74,698               1,104,191
Prepaid income taxes                            (320,297 )          959,142              (1,279,439 )

Change in over-collection of gas costs 1,084,735 (2,360,972 )

             3,445,707
Deferred taxes                                   684,028            755,994                 (71,966 )

Accounts payable and accrued expenses (2,745,377 ) 191,054

             (2,936,431 )
Rate refund                                    2,507,422          1,320,167               1,187,255
Other                                           (970,612 )         (885,131 )               (85,481 )

Net cash provided by operating activities $ 14,697,704$ 13,503,795

$ 1,193,909

Cash Flows Used in Investing Activities:


Investing activities primarily consist of expenditures related to investment in
Roanoke Gas' utility plant projects, which includes replacing aging natural gas
pipe with new plastic or coated steel pipe, improvements to the LNG plant and
gas distribution system facilities and expansion of its natural gas system to
meet the demands of customer growth, as well as the continued investment by
Midstream in the MVP. Roanoke Gas' expenditures related to its pipeline renewal
program and other system and infrastructure improvements were nearly $21.9
million in fiscal 2019 compared to $23.3 million in fiscal 2018 and $20.7
million in fiscal 2017. Roanoke Gas renewed 8.4 miles of natural gas
distribution main and replaced 875 service lines to customers in fiscal 2019.
This compares to 8.3 miles of main and 496 service lines in fiscal 2018 and 9
miles of main and 459 service lines in fiscal 2017. The current renewal program
is focused on the replacement of pre-1973 first generation plastic pipe. In
addition, the Company's capital expenditures included costs to extend natural
gas distribution mains and services to 553 new customers in fiscal 2019 compared
to 451 new customers in fiscal 2018 and 499 new customers in fiscal 2017.
Roanoke Gas is constructing two gate stations to access the MVP and has nearly
completed the extension of the gas distribution system to connect to these
stations. These two stations will provide additional gas supply as well as
provide natural gas to currently unserved areas once MVP is operational. The LNG
facility is being upgraded with the installation of two new boilers and a new
natural gas generator. The MVP interconnect projects and the LNG upgrades
account for 70% of the construction work in progress as of September 30, 2019.
Fiscal 2018 projects included a major system reinforcement to increase capacity
within certain areas of the Company's natural gas distribution system, the
extension of gas service to a new industrial park, which included system
reinforcement to the surrounding service area, and progress toward extending
Roanoke Gas' distribution pipeline to interconnect with the MVP. Depreciation
covered approximately 35% of the current year's capital expenditures compared to
30% for 2018 and 31% for 2017, with the balance provided from other operating
cash flows and borrowings.

Capital expenditures are expected to remain at elevated levels over the next few
years. The Company is continuing its focus on replacing the remaining pre-1973
first generation plastic pipe with modern polyethylene pipe. This renewal
project is expected to be completed by 2024. The current capital budget for
fiscal 2020 is expected to be on a level consistent with fiscal 2019 and 2018.
Under this budget, the Company plans to complete its interconnect with the MVP,
finish the LNG upgrades, conduct system reinforcements and expand service to new
customers. The Company expects to increase its borrowing activity, as well as
consider additional equity investment, to meet the funding requirements of these
planned expenditures.

Investing cash flows also reflect Midstream's $20,965,907 fiscal 2019 funding of
its participation in the LLC. Midstream's total expected funding increased to
between $53 and $55 million as discussed below, with anticipated cash investment
for fiscal 2020 to be as much as $15 million. Funding for the investment in the
LLC is provided through the $26 million credit facility, which matures in 2020
and two unsecured notes in the combined amount of $24 million. The Company is in
the process of negotiating additional funding to meet the projected increase as
well as an extension of the credit facility beyond 2020. More information
regarding the credit facility is provided in Note 7 and under the Equity
Investment in Mountain Valley Pipeline section below.



                                       25
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Cash Flows Provided by Financing Activities:


Financing activities generally consist of borrowings and repayments under debt
agreements, issuance of stock and the payment of dividends. Net cash flows
provided by financing activities were $29,516,000, $20,841,000 and $9,938,000 in
fiscal 2019, 2018 and 2017, respectively. As mentioned above, the Company uses
its line-of-credit to fund seasonal working capital and provide temporary
financing for capital projects, which is then converted into longer-term debt or
equity financing. The increase in financing cash flows derived from Midstream's
net borrowings of more than $22 million to finance its investment in MVP and the
issuance of notes by Roanoke Gas. The Company also realized $1.7 million from
the issuance of stock through DRIP activity and the exercise of options.
Dividend payments exceeded $5.2 million as the annualized dividend rate per
share increased from $0.62 to $0.66. In fiscal 2018, Resources issued 700,000
shares of stock through an equity offering for $15.1 million and invested the
proceeds in Roanoke Gas to convert a portion of the debt financing of the
capital budget provided by the line-of-credit to equity by refinancing the
outstanding balance under the line-of-credit. The Company's consolidated
capitalization was 44.5% equity and 55.5% long-term debt at September 30, 2019,
exclusive of unamortized debt expense. This compares to 53.0% equity and 47.0%
long-term debt at September 30, 2018. The long-term debt as a percent of
long-term capitalization increased from last year due to the debt issues listed
below.

In June 2019, Midstream entered into two unsecured promissory notes and loan
agreements in the total aggregate principal amount of $24,000,000. The first
note was for a 7-year term in the amount of $14,000,000 at an interest rate of
30-day LIBOR plus 115 basis points. Midstream entered into a related swap
agreement to convert the variable interest rate to a 3.24% fixed rate. The
second note was for a 5-year term in the amount of $10,000,000 at an interest
rate of 30-day LIBOR plus 120 basis points. Midstream also entered into a swap
agreement on this note to convert the variable interest rate to a 3.14% fixed
rate.

On June 5, 2019, Roanoke Gas entered into an agreement to issue notes in the
aggregate principal amount of $10,000,000. These notes are scheduled to be
issued on the day of closing currently proposed for December 6, 2019. These
notes will have a 10-year term from the date of issue at a fixed interest rate
of 3.60%. The proceeds from these notes will be used to finance a portion of
Roanoke Gas' capital budget.

On March 28, 2019, Roanoke Gas issued notes in the aggregate principal amount of $10,000,000. These notes have a 12-year term with a fixed interest rate of 4.41%.


On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit
agreement with a two-year term expiring March 31, 2021, replacing the prior
line-of-credit agreement scheduled to expire March 31, 2020. The new agreement
maintains the same variable interest rate based on 30-day LIBOR plus 100 basis
points and availability fee of 15 basis points applied to the unused balance on
the note. The agreement retains the multi-tiered borrowing limits to accommodate
seasonal borrowing demands and minimize borrowing costs. The total available
borrowing limits during the term of the agreement range from $3,000,000 to
$30,000,000. As the agreement is for a two-year term, amounts drawn against the
new agreement are generally considered to be non-current.

On February 19, 2019, Midstream entered into an agreement with the lending
institutions to amend its existing non-revolving credit agreement and related
notes that provide financing for the MVP project. The amendment increased total
borrowing limits to $50 million through the date of maturity to meet the
projected funding requirements for completion of the MVP. With the exception of
the increase in borrowing limits, all remaining terms under the notes remain
unchanged including the variable-interest rate based on 30-day LIBOR plus 135
basis points. Midstream used the proceeds from the two notes issued in June 2019
to pay down the balance on the notes. As the notes were issued under a
non-revolving credit agreement, the borrowing limit under this credit facility
was reduced from $50 million to $26 million.

Off-Balance Sheet Arrangements

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

Contractual Obligations and Commitments


The Company has incurred various contractual obligations and commitments in the
normal course of business. As of September 30, 2019, the estimated recorded and
unrecorded obligations are as follows:

                                       26
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Recorded contractual            Less than 1
obligations:                        year         1-3 Years        4-5 Years        After 5 Years          Total
Long-Term Debt - Notes Payable
(1)                             $        -     $ 23,012,200$ 10,000,000$    62,500,000$  95,512,200
Long-Term Debt - Line of Credit
(2)                                      -        8,172,473                -                   -         8,172,473
Total                           $        -     $ 31,184,673$ 10,000,000$    62,500,000$ 103,684,673

(1) See Note 7 to the consolidated financial statements.
(2) See Notes 6 and 7 to the consolidated financial statements. New line-of-credit agreement executed for a 2-year
term, expiring March 31, 2021. Amounts drawn against agreement are considered non-current as they are not subject to
repayment within 12-months.


Unrecorded contractual
obligations, not reflected
in consolidated balance
sheets in accordance with
US GAAP:                    Less than 1 year     1-3 Years        4-5 Years        After 5 Years         Total
Pipeline and Storage
Capacity (3)                $   11,532,130$ 22,391,052$ 12,944,441$     1,950,134$ 48,817,757
Gas Supply (4)                           -                -                -                   -                -
Interest on Line-of-Credit
(5)                                 40,806           22,750                -                   -           63,556
Interest on Notes Payable
(6)                              3,509,997        5,902,370        3,185,711          15,396,752       27,994,830
Pension Plan Funding (7)                 -                -                -                   -                -
Investment in MVP (8)           14,917,024        1,354,456                -                   -       16,271,480
Franchise Agreements (9)           110,521          231,088          245,161           1,818,339        2,405,109
Other Obligations (10)             207,085          228,116            3,596              12,105          450,902
Total                       $   30,317,563$ 30,129,832     $ 

16,378,909 $ 19,177,330$ 96,003,634


(3) Recoverable through the PGA process.
(4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at
the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 12 to the
consolidated financial statements.
(5) Accrued interest on line-of-credit balance at September 30, 2019, including minimum facility fee on unused
line-of-credit. See Note 6 to the consolidated financial statements.
(6) Calculated interest payments notes payable included in Note 7 to the consolidated financial statements.
(7) Estimated minimum funding requirement assuming application of credit balances in plan to offset funding.
Minimum funding requirements beyond five years is not available. See Note 9 to the consolidated financial
statements for the planned funding in fiscal 2019.
(8) Projected remaining funding of the Company's 1% interest in the LLC as entered into on October 1, 2015.
(9) Franchise tax obligations due Roanoke City, Salem City and Town of Vinton per 20-year term agreements. See Note
12 to the consolidated financial statements.
(10) Various lease, maintenance, equipment and service contracts.



Equity Investment in Mountain Valley Pipeline


On October 1, 2015, Midstream entered into an agreement to become a 1% member in
the LLC. The purpose of the LLC is to construct and operate the Mountain Valley
Pipeline, a natural gas pipeline connecting the Equitrans gathering and
transmission system in northern West Virginia to the Transco interstate pipeline
in south central Virginia.

Management believes the investment in the LLC will be beneficial for the
Company, its shareholders and southwest Virginia. In addition to the Midstream's
potential returns from its investment in the LLC, Roanoke Gas will benefit from
another delivery source of natural gas into its distribution system. Currently,
Roanoke Gas is served by two pipelines and a liquefied natural gas storage
facility. Damage to or interruption of supply from any of these sources,
especially during the winter heating season, could have a significant impact on
the Company's ability to serve its customers. A third pipeline will reduce the
impact from such an event. In addition, the current pipeline path provides the
Company with a more economically feasible opportunity to provide natural gas
service to currently unserved areas within the Company's certificated service
territory.


                                       27
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On October 13, 2017, FERC issued the CPCN for the MVP. In January 2018, FERC
began issuing Notices to Proceed, which granted the LLC permission to begin
construction activities as the LLC also had received the necessary federal
permits and the required Virginia and West Virginia environmental agency permits
specified by FERC. Since construction began on the pipeline, the LLC has
encountered various challenges, including pipeline protesters, legal challenges
to various federal and state permits resulting in stop orders and FERC
intervention. In July 2018, the Fourth Circuit rescinded permits allowing the
pipeline to cross a 3.6 mile section of the Jefferson National Forest. In
October 2018, the same court vacated the West Virginia water crossing permits
with the Army Corp of Engineers subsequently pulling the related Virginia
permits. In October 2019, FERC issued a project-wide order halting
forward-construction progress in response to the October 11, 2019, order by the
Fourth Circuit granting a stay of MVP's Biological Opinion and Incidental Take
Statement issued by the U.S. Fish and Wildlife Service in November 2017. The
FERC order directed activity on the pipeline to be focused on restoration and
stabilization activities to protect the environment along the pipeline. The LLC
is currently working with all regulatory entities and the Fourth Circuit to
resolve these issues and the managing partner anticipates the reinstatement of
these permits and authorization.

As a result of the most recent action by FERC, the managing partner of the LLC
has revised the timeline for completing the MVP. The full in-service date for
the pipeline to be operational is now targeted for late 2020. Although the total
MVP project is approximately 90% completed, additional time is needed to resolve
the issues above for the remaining construction to be completed. Furthermore,
these delays have resulted in a revised estimate for the total project cost of
between $5.3 and $5.5 billion, of which Midstream's portion is expected to be
between $53 million and $55 million. The additional delays in completing the
project combined with the increased costs will reduce the corresponding return
on investment, absent a regulatory action, which could provide for the recovery
of these higher costs. With the recently revised extended time line and higher
projected costs, Midstream will need additional funding to fulfill its
obligation. The Company is in the process of negotiating with Midstream's
existing debt holders for additional funding and an extension of the credit
facility beyond 2020. See Note 15 regarding an increase in the Company's
participation in MVP and corresponding $1.6 million expected funding increase in
its investment.

The current earnings from the investment in MVP relates to the AFUDC income
generated by the deployment of capital in the design, engineering, materials
procurement, project management and ultimately construction phases of the
pipeline. AFUDC is an accounting method whereby the costs of debt and equity
funds used to finance facility infrastructure are credited to income and charged
to the cost of the project. The level of investment in MVP, as well as the
AFUDC, will continue to grow as construction activities continue. When the
pipeline is completed and placed into service, AFUDC will cease. Once
operational, earnings will be derived from capacity charges for utilizing the
pipeline.

On April 11, 2018, the LLC announced the MVP Southgate project, which is a
planned 70 mile pipeline extending from the MVP mainline in Virginia to delivery
points in North Carolina. Midstream will be a less than 1% investor in the
Southgate project and, based on current project cost estimates, will invest
between $1.8 million and $2.5 million toward the project. On November 6, 2018,
the LLC filed with FERC the formal application request to construct the
Southgate pipeline. Unlike with its investment in the MVP, where the Company was
an important member of the project and where the pipeline would benefit Roanoke
Gas by providing additional natural gas access to its distribution system,
Midstream's participation in the Southgate project is for investment purposes
only. The targeted in-service date for Southgate is the end of calendar 2020.
Any further delays in the completion of the MVP will extend the completion date
of Southgate.

Regulatory and Tax Reform

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

On June 28, 2019, the SCC staff issued their report and recommendations related
to the rate application. The SCC staff report included a recommendation for a
non-gas rate increase of approximately $6.5 million. Management reviewed the SCC
staff report and submitted rebuttal testimony to certain proposed adjustments
included in the report. At the hearing held on August 14 and 15, the Company
addressed specific differences with SCC staff, including the proposed return on
equity, the exclusion of certain infrastructure items from rate base, changes in
customer class rate design and the exclusion of a portion of the regulatory
assets associated with the ESAC costs. The hearing examiner's report is not
expected until December 2019, with a final order expected from the SCC in early
2020. Based on its assessment of the

                                       28
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SCC staff report and the rebuttal testimony and evidence presented at the
hearing, management has established a provision for a refund of revenues
collected in excess of management's expectations regarding the final rate award.
On November 19, 2019, the hearing examiner issued his report, which was
subsequently revised on November 26, 2019. Although the revised report indicated
a more favorable result than reflected in management's estimates, no adjustment
was made to the rate refund estimate included in the September 30, 2019
financial statements, as recent rate orders from the SCC Commissioners have
differed from the findings included in the hearing examiners' reports. The
Company will continue to monitor information and refine its assumptions
regarding its refund estimates until such time as the SCC issues its final order
and new billing rates are finalized.

Since its prior rate case in 2013, Roanoke Gas has deferred costs attributable
to compliance and safety related expenses. These ESAC expenses were above and
beyond a base line for those costs previously provided for in non-gas base rates
and have been included in the current rate application for recovery over a
five-year period. As noted above, the SCC staff report recommended excluding a
portion of these costs from rate recovery. The Company has evaluated the
situation and adjusted the valuation based on its assessment of the resolution.
If the ultimate result is different from management's assessment, any difference
would be further adjusted following a final order from the SCC.

As noted above, the general rate case application incorporated the effects of
tax reform, which reduced the federal tax rate for the Company from 34% to 21%.
Roanoke Gas recorded two regulatory liabilities to account for this change in
the federal tax rate. The first regulatory liability relates to the excess
deferred taxes associated with the regulated operations of Roanoke Gas. As
Roanoke Gas had a net deferred tax liability, the reduction in the federal tax
rate required the revaluation of these excess deferred income taxes to the 21%
rate at which the deferred taxes are expected to reverse. The excess net
deferred tax liability for Roanoke Gas' regulated operations was transferred to
a regulatory liability, while the revaluation of excess deferred taxes on the
unregulated operations of the Company was recognized in income tax expense in
the first quarter of fiscal 2018. A majority of the regulatory liability for
excess deferred taxes was attributable to accelerated tax depreciation related
to utility property. In order to comply with the IRS normalization rules, these
excess deferred income taxes must be refunded to customers and flowed through
income tax expense based on the average remaining life of the corresponding
assets, which approximates 28 years. The current and non-current portions are
reflected in regulatory liabilities and detailed in Note 1.

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. Beginning with the implementation of the new non-gas
base rates in January 2019, Roanoke Gas began returning the excess revenues to
customers over a 12-month period. The estimated refund amounts for both the
excess deferred taxes and the excess revenues associated with the reduction in
the federal income tax rate were subject to review and adjustment by the SCC,
which was done by its staff in connection with its audit of the rate case
application. The SCC staff report agreed with the refund amounts reflected in
the Company's financial statements, and, assuming no changes as a result of the
hearing examiner's report or by the Commissioners, these amounts will be
reflected in the final order.

The Company continues to recover the costs of its infrastructure replacement
program through its SAVE Plan. The original SAVE Plan was designed to facilitate
the accelerated replacement of aging natural gas pipe by providing a mechanism
for the Company to recover the related depreciation and expenses and return on
rate base of the additional capital investment without the filing of a formal
application for an increase in non-gas base rates. Since the implementation and
approval of the original SAVE Plan in 2012, the Company has modified, amended or
updated the Plan each year to incorporate various qualifying projects. In May
2019, the Company filed its most recent SAVE Plan and Rider, which continues the
focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of
a natural gas transfer station as well as extending the SAVE Plan to September
30, 2024. In September 2019, the SCC approved the updated SAVE Plan and Rider
effective with the October 2019 billing cycle. The new SAVE Rider is designed to
collect approximately $1.1 million in annual revenues, an increase from the
approximate $500,000 in annual revenues under the prior SAVE rates. With the
inclusion of all previous SAVE investments through December 31, 2018 into the
base non-gas rate application, the current SAVE Rider reflects only the recovery
of qualifying SAVE Plan investments made since January 2019. In addition, the
SAVE application includes a refund factor to return approximately $543,000 in
SAVE revenue over-collections from 2018, primarily resulting from the effect of
the reduction in the federal income tax rate.

As noted above, Roanoke Gas contracts with a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the

                                       29
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transportation and storage rights, the asset manager credits Roanoke Gas monthly
for an amount referred to as a utilization fee. In June 2018, the SCC issued an
order, retroactive to April 1, 2018, approving implementation of an incentive
mechanism, whereby the Company shares the utilization fee with its customers.
Under the incentive mechanism beginning April 1 each year, customers receive the
initial $700,000 of the utilization fee collected through reduced gas costs, and
thereafter, every additional dollar received during the annual period is split
25% to the Company and 75% to its customers. Being in effect for the entire 2019
fiscal year, revenue sharing revenues increased by $313,000 over fiscal 2018.

On February 7, 2019, the SCC issued a final order granting a CPCN to furnish gas
service to all of Franklin County, Virginia. If the Company does not furnish gas
service to the designated area within five years of the date of the order, the
CPCN granting authority to serve Franklin County will be terminated. All other
CPCNs held by the Company are for territories currently served by Roanoke Gas
and are intended for perpetual duration.

On August 8, 2019, the SCC issued an order granting Roanoke Gas' authority to
issue up to $40 million in short-term debt and up to $100 million of long-term
debt and/or common equity. This order replaces the prior financing authorization
that expired on September 30, 2019. The new authorization request is for 5 years
ending on September 30, 2024 and will allow Roanoke Gas to continue to finance
its infrastructure replacement program and system growth.

Roanoke Gas' provision for depreciation is computed principally based on
composite rates determined by depreciation studies. These depreciation studies
are required to be performed on the regulated utility assets of Roanoke Gas at
least every five years. The previous depreciation study was completed and
implemented in fiscal 2014. On June 11, 2019, Roanoke Gas submitted its current
depreciation study, which incorporates all of the new and replacement
infrastructure and equipment placed in service since the last study. In
September 2019, the SCC administratively approved the depreciation study and
directed the Company to implement the new rates retroactive to October 1, 2018.
The new depreciation rates resulted in a reduction of total depreciation expense
of $32,570 for fiscal 2019.

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.

Revenue recognition - Regulated utility sales and transportation revenues are
based upon rates approved by the SCC. The non-gas cost component of rates may
not be changed without a formal rate application and corresponding authorization
by the SCC in the form of a Commission order; however, the gas cost component of
rates is adjusted quarterly, or more frequently if necessary, through the PGA
mechanism. When the Company files a request for a non-gas rate increase, the SCC
may allow the Company to place such rates into effect subject to refund pending
a final

                                       30
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order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information.


The Company has recorded an estimate for a refund related to the implementation
of the new non-gas base rates effective January 1, 2019. This estimate reflects
management's evaluation of adjustments proposed by the SCC staff in their report
issued on June 28, 2019, the rebuttal testimony provided by the Company and an
assessment of the pending determinations from the hearing. This estimate could
change as more information becomes available and until a final order is issued.
The actual refund may be more or less than the amount included in the
consolidated financial statements.

The Company also bills customers through a SAVE Rider that provides a mechanism
to recover on a prospective basis the costs associated with the Company's
expected investment related to the replacement of natural gas distribution pipe
and other qualifying projects. 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 FASB
ASC No. 980, Regulated Operations, the Company recognizes billed revenue related
to SAVE projects and from the WNA to the extent such revenues have been earned
under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The
billing cycle for most customers does not coincide with the accounting periods
used for financial reporting. The Company accrues estimated revenue for natural
gas delivered to customers but not yet billed during the accounting period based
on weather during the period and current and historical data. The consolidated
financial statements include unbilled revenue of $1,236,384 and $911,657 as of
September 30, 2019 and 2018, 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 Company outsourced its credit
and collections function in 2017 as part of its strategic decision to move the
call center, billing and other customer service functions to a third-party
provider with significant utility experience. These changes have been
incorporated into the current valuation model for accounts receivable, which
used historical information based on collection functions previously handled
in-house.

Pension and Postretirement Benefits - The Company offers a defined benefit
pension plan ("pension plan") and a postretirement medical and life insurance
plan ("postretirement plan") to eligible employees. The expenses and liabilities
associated with these plans, as disclosed in Note 9 to the consolidated
financial statements, are based on numerous assumptions and factors, including
provisions of the plans, employee demographics, contributions made to the plan,
return on plan assets and various actuarial calculations, assumptions and
accounting requirements. In regard to the pension plan, specific factors include
assumptions regarding the discount rate used in determining future benefit
obligations, expected long-term rate of return on plan assets, compensation
increases and life expectancies. 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.


                                       31
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In selecting the discount rate to be used in determining the benefit liability,
the Company utilized the FTSE Pension Discount Curve, formerly the Citigroup
yield curves, which incorporate the rates of return on high-quality,
fixed-income investments that corresponded to the length and timing of benefit
streams expected under both the pension plan and postretirement plan. The
Company used a discount rate of 3.03% and 3.00%, respectively, for valuing its
pension plan liability and postretirement plan liability at September 30, 2019.
These discount rates represent a significant decline from the 4.11% and 4.09%
rates used for valuing the corresponding liabilities at September 30, 2018. The
drop in the discount rates is evidenced by the change in 30-year Treasury yield,
which decreased from 3.19% last year to 2.12% at September 30, 2019 as well as
corporate bond rates, which experienced a similar decline. The reduction in the
discount rates was the primary variable in increasing the benefit obligations of
both the pension and the postretirement plan. Mortality assumptions were based
on the RP-2014 Mortality Table, adjusted to 2006, with generational mortality
improvements using Projection Scale MP-2018 for the current year valuation.

Over the last few years, management has focused on reducing risk in the
Company's defined benefit plans with a greater emphasis on pension plan risk. In
2016, the Company offered a one-time, lump-sum payout of the pension benefit to
vested employees who were not receiving payments under the plan. In 2017, the
Company implemented a "soft freeze" to the pension plan whereby employees hired
on or after January 1, 2017 would not be eligible to participate. Employees
hired prior to that date continue to accrue benefits based on compensation and
years of service. This "soft freeze" mirrored the strategy in 2000 when the
Company implemented a similar freeze in its postretirement medical plan. These
strategies have reduced liability growth by not allowing new employees into the
plans and reducing the number of participants entitled to future benefits.

The Company also has focused on its asset investment strategy. An aggressive
funding strategy combined with strong investment returns have allowed pension
plan assets to increase by $10.5 million over the last three years, while
liabilities increased only $6.1 million during the same period for the reasons
noted above. As of September 30, 2019, the pension plan is at a 94% funded
status. With future pension liability growth associated with increasing benefits
limited to employees hired prior to the freeze, the Company evaluated measures
that would mitigate the effect of changing interest rates on the pension
liability. As the pension liability represents the present value of future
pension payments, an increase in the discount rate used to value the pension
obligation would reduce the liability while a reduction in the discount rate
would lead to an increase in the pension liability. With plan funded status
above 90%, the Company moved to a more conservative asset allocation model in
fiscal 2018 by transitioning from a 60% equity and 40% fixed income allocation
to a 40% equity and 60% fixed income allocation for pension assets. The fixed
income portion of the investments were invested using an LDI approach. As 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 40% 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 assets as
increasing medical and insurance costs warrant the need for a continued higher
allocation to equities for future plan asset growth potential. Though not to the
same magnitude, the postretirement plan assets increased by $2 million and
liabilities decreased by $0.5 million over the last three-year period.

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


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 )


Funded status - September 30, 2018    Pension        Postretirement         Total
Benefit Obligation                 $ 28,850,299$    16,207,322$ 45,057,621
Fair value of assets                 28,184,697          12,924,957       41,109,654
Funded status                      $   (665,602 )$    (3,282,365 )$ (3,947,967 )



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

                                       32
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long-term rate of return with its investment advisors to determine the rates
used in each plan's actuarial assumptions. Under the current allocation model
for the pension plan, management determined that a 5.50% long-term rate of
return assumption remained appropriate considering the asset allocation and
market environment. Likewise, as the asset allocation remained unchanged for the
postretirement plan, management determined that a 4.26% expected long-term rate
of return is reasonable. Management will continue to re-evaluate the return
assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined
benefit pension plans, the Company will have no minimum funding requirements
next year. However, management plans to continue its pension funding plan by
contributing at least the minimum annual pension contribution requirement or its
expense level for subsequent years. The Company currently expects to contribute
approximately $800,000 to its pension plan and $400,000 to its postretirement
plan in fiscal 2020 with an ongoing goal to improve both plans' funded status.
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  %       $       145,000$      1,497,000
Rate of return on plan assets                     -0.25  %                83,000                  N/A
Rate of increase in compensation                   0.25  %                53,000              280,000



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
Actuarial Assumptions - Postretirement Plan  Change in Assumption        Benefit Cost        Benefit Obligation
Discount rate                                         -0.25  %       $            39,000     $        753,000
Rate of return on plan assets                         -0.25  %                    32,000                  N/A
Medical claim cost increase                            0.25  %                    78,000              722,000



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, 2019
related to the three variable rate notes held by the Company. See Note 7 for
additional information regarding the swaps.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.



The Company is exposed to market risks associated with interest rates and
commodity prices. Interest rate risk is related to the Company's outstanding
variable rate debt. Commodity price risk is experienced by the Company's
regulated natural gas operations. The Company's risk management policy, as
authorized by the Company's Board of Directors, allows management to enter into
derivatives for the purpose of managing commodity and financial market risks of
its business operations.




                                       33

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Interest Rate Risk
The Company is exposed to market risk related to changes in interest rates
associated with its borrowing activities. As of September 30, 2019, the Company
has $8,172,473 outstanding under its variable-rate line-of-credit with an
average balance outstanding during the year of $6,049,527. The Company also had
$16,012,200 outstanding under two 5-year variable rate unsecured term loans. A
hypothetical 100 basis point increase in market interest rates applicable to the
Company's variable-rate debt outstanding during the year would have resulted in
an increase in interest expense for the current year of approximately $314,128.
The Company's remaining debt is at a fixed rate or have interest rate swaps in
place to convert variable rate debt to a fixed interest rate.

Commodity Price Risk
The Company is also exposed to market risks through its natural gas operations
associated with commodity prices. The Company's hedging and derivatives policy,
as authorized by the Company's Board of Directors, allows management to enter
into both physical and financial transactions for the purpose of managing the
commodity risk of its business operations. The policy also specifies that the
combination of all commodity hedging contracts for any 12-month period shall not
exceed a total hedged volume of 90% of projected volumes. The policy
specifically prohibits the use of derivatives for the purposes of speculation.

The Company manages the price risk associated with purchases of natural gas by
using a combination of LNG storage, underground storage gas, fixed price
contracts, spot market purchases and derivative commodity instruments including
futures, price caps, swaps and collars.

At September 30, 2019, the Company had no outstanding derivative instruments to
hedge the price of natural gas. The Company had approximately 2,390,000 dths of
gas in storage, including LNG, at an average price of $2.70 per dth compared to
2,441,000 dths at an average price of $3.13 per dth last year. The SCC currently
allows for full recovery of prudent costs associated with natural gas purchases,
and any additional costs or benefits associated with the settlement of
derivative contracts and other price hedging techniques are passed through to
customers when realized through the regulated natural gas PGA mechanism.

© Edgar Online, source Glimpses

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