RGC RESOURCES INC (RGCO)

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,500 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary.  Midstream, a wholly owned subsidiary of Resources, is a less than 1% investor in both the MVP and Southgate. More information regarding the investment in MVP is provided below and under the Equity Investment in Mountain Valley Pipeline section.

The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions and rates charged to customers for natural gas service, safety standards, extension of service and depreciation. Nearly all of the Company’s revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates and fees authorized by the SCC. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.  These rates are determined based on various rate applications filed 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 in place at that time.  The investment in replacing and upgrading existing infrastructure, as well as recovering increases in non-gas expenses due to inflationary pressures, regulatory requirements or operation needs, are generally not recoverable until a formal rate application is filed to include additional investment and higher costs, and new non-gas base rates are approved.

The Company is also subject to regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines, as well as the FERC, which regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.

Beginning January 1, 2023, Roanoke Gas implemented interim, non-gas base rates designed to provide $8.55 million in additional annual revenues in response to higher operating costs and to recover its investment in non-SAVE related projects since the prior non-gas base rate increase in fiscal 2019. Revenues from the SAVE Plan and Rider were incorporated into the interim, non-gas base rates. On December 19, 2023, the SCC issued a final order approving a non-gas base rate increase of $7.45 million. The order also directed Roanoke Gas to refund the excess revenues collected during the time the interim rates were in effect with interest. Refunds to customers, which were accrued in fiscal 2023 and reflected in regulatory liabilities, were made in February 2024. On February 2, 2024, primarily in response to continued inflationary pressures, Roanoke Gas filed for a non-gas base rate increase of $4.33 million.  The filing also reflected an increase in the Company's authorized return on equity from 9.44% to 10.35%. The new interim non-gas base rates went into effect for customer billings on or after July 1, 2024, subject to refund. On October 16, 2024, the Company reached a settlement with the SCC staff on all outstanding issues in the case.  Under the terms of the settlement, the Company agreed to an annual incremental revenue requirement increase of $4.08 million based on a return on equity of 9.90%.

Following extended periods of regulatory and judicial delays, as well as receipt of authorization from the FERC, the MVP entered into service on June 14, 2024 and became available for interruptible or short-term firm transportation service. On July 1, 2024, the MVP commenced long-term firm capacity obligations. See the Equity Investment in Mountain Valley Pipeline section for additional information on the MVP.

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 to customer bills and 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, RNG and PGA.

The SAVE Plan and Rider provides the Company with a mechanism through which it recovers costs related to SAVE qualified infrastructure investments on a prospective basis, until such time a formal rate application is filed incorporating these investments in non-gas base rates.  The SAVE Plan and Rider were reset effective January 1, 2023, when the recovery of all prior SAVE Plan investment was incorporated into the new non-gas base rates.  Roanoke Gas filed and received approval from the SCC for a new SAVE Plan and Rider with new rates placed into effect on October 1, 2023, and as a result, SAVE Plan revenues declined to approximately $461,000 in fiscal 2024 from approximately $1,104,000 in fiscal 2023.  Roanoke Gas filed and received approval from the SCC for an updated annual SAVE Rider rate to become effective October 1, 2024 that will result in approximately $1,389,000 of SAVE-related revenues during fiscal 2025. See Note 4 of the consolidated financial statements for additional information regarding the SAVE Plan and Rider.

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The WNA mechanism 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 a level of price protection when the weather is colder than normal. The WNA allows the Company to recover from customers the lost margin, excluding gas costs, from the impact of warmer-than-normal weather and correspondingly requires the Company to refund to customers the excess margin earned for colder-than-normal weather.  The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day and thereby estimates the revenue adjustment based on weather variance from normal.  Any billings or refunds related to the WNA are completed following each WNA year, which extends for the 12-month period from April to March. The Company recorded approximately $3,761,000 and $3,005,000 in additional revenues under the WNA for weather that was approximately 20% and 16% warmer than normal for the fiscal years ended September 30, 2024 and 2023, respectively.  The number of heating degree days used to determine normal can change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding warmer than normal years to replace colder years, the number of heating degree days that defines normal has trended downward over the last several years.

The Company also has an approved rate structure that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue by applying the ICC factor, based on the Company’s weighted-average cost of capital, including interest rates on short-term and long-term debt, and the Company’s authorized return on equity, to the average cost of natural gas inventory during the period.  Total ICC revenues decreased from approximately $967,000 in fiscal 2023 to $728,000 in fiscal 2024 due to lower natural gas commodity prices during the 2023 summer storage injection season resulting in a lower average cost of natural gas in storage.  The average price of gas in storage at September 30, 2024 declined by 23% compared to the same period last year.  Accordingly, fiscal 2025 ICC revenues are expected to continue to remain below the prior year's levels.

In March 2023, Roanoke Gas began the operation of the RNG facility to produce commercial quality biogas for delivery into its distribution system through a cooperative agreement with the Western Virginia Water Authority.  With SCC approval, Roanoke Gas is allowed to recover the costs associated with the investment in RNG facilities and related operating costs through an RNG Rider added to customer bills.  The customer benefits from this program through the monetization of environmental credits generated through RNG production, in which these credits are returned to customers through the RNG Rider.  Total RNG revenue increased from approximately $712,000 in fiscal 2023 to $1,629,000 in fiscal 2024 as the facility was operational for a full twelve months in the current year compared to seven months in the prior year. See Note 4 of the consolidated financial statements for more information on RNG.

The cost of natural gas is a pass-through cost and is independent of the Company's non-gas rates. Accordingly, the Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs through a quarterly filing (or more frequent if necessary) with the SCC. Once SCC approval is received, the Company adjusts the gas cost component of its rates.  As actual costs and usage 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.

Inflation and Rising Prices

Natural gas commodity, delivery and storage capacity costs constitute the single largest expense of the Company, representing 53% of fiscal 2024 total operating expenses.  After peaking in December 2022, natural gas commodity prices decreased significantly through the remainder of fiscal 2023 and fiscal 2024.   The decline in prices was primarily due to improved supply availability resulting from a warm winter season.  Roanoke Gas recovers natural gas costs through the PGA mechanism as noted above; however, in times where commodity prices rapidly increase, the timing of recovery may lag.  Increasing natural gas prices, especially in relation to other energy options, may lead to reductions in energy consumption through customer conservation or fuel switching.  In addition, there is potential for higher bad debts related to customers' inability to pay higher natural gas bills.

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Inflation, due to supply chain delays, labor shortages and limited availability of critical supplies, among other factors, affects the Company through increases in non-gas expenses such as labor, employee benefits, materials and supplies, contracted services, corporate insurance and other areas.  The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas base rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas base rate application process can result in an inherent lag in non-gas expense recovery.  Therefore, authorized non-gas base rates may not keep pace with rising costs during inflationary periods.  Management regularly evaluates the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas base rate adjustment. Accordingly, management filed a non-gas rate application in February 2024 to incorporate increased expense levels from continued inflationary pressures since the last non-gas base rate application.  These new non-gas base rates were implemented effective July 1, 2024, subject to refund.  See Note 4 of the consolidated financial statements for more information, including reaching settlement with SCC staff.

Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which are primarily associated with the utility segment. Additional segment analysis is provided when Midstream's investment in affiliates represents a significant component of the comparison.  Net income increased by $461,614 from the prior year primarily due to AFUDC and earnings from the MVP and the implementation of new non-gas base rates effective July 1, 2024, partially offset by increased inflationary pressures on operating expenses and higher interest rates.

The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated statement of income under the line item cost of gas - utility. The cost of natural gas, 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, is passed through to customers at cost.  Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace gross margin, 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. A reconciliation between gross utility margin and gross margin is presented under the Gross Utility Margin section below.

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

Fiscal Year 2024 Compared with Fiscal Year 2023

The tables below reflect operating revenues, volume activity and heating degree days.

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Total gas utility operating revenues for the year ended September 30, 2024 decreased by 13% from the year ended September 30, 2023 primarily due to significantly lower natural gas commodity prices and lower deliveries due to warmer weather more than offsetting the implementation of a non-gas base rate increase and increases in WNA and RNG revenues.  Natural gas commodity prices for fiscal 2024 purchases declined by 43% per DTH from the prior year and the total commodity component of gas costs decreased by 44% per DTH from the prior year. Total gas costs, including pipeline and storage demand charges, decreased by 29% compared to a year ago, which corresponds to a 31% decline in the gas cost component included in total customer billing rate. Corresponding to the lower average price of natural gas in storage during 2024, ICC revenues declined 25%.  In addition, total heating degree days decreased by 6% from the same period last year, resulting in a 2% decline in the weather-sensitive residential and commercial volumes, while transportation and interruptible volumes, primarily driven by business activity rather than weather, increased by 1%.  The non-gas base rate increases implemented in 2023 and 2024 were the main contributing factors to an approximate $1.7 million increase in non-gas volumetric revenues, net of lower delivered volumes, and a $522,000 increase in customer base charge revenue.  Additionally, the operation of the RNG facility for a full twelve months in the current year compared to seven months in the prior year resulted in increased revenues of approximately $917,000.

Gross utility margin increased over the prior fiscal year primarily as a result of the implementation of new non-gas base rates, net of SAVE, WNA and RNG revenue, offset by the reductions in ICC revenues. When adjusted for WNA, the volumetric margin increased by approximately $2,430,000. Base charge revenues increased by approximately $522,000 due to the non-gas base rate increase. The RNG Rider contributed an additional $917,000 to margin, as it was operational for all twelve months of fiscal 2024 compared to seven months during fiscal 2023, and ICC revenue declined by $239,000 due to lower cost of gas in storage.

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

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Reconciliation between gross utility margin and gross margin is presented below:

Operations and Maintenance Expense - Operations and maintenance expense increased by $2,450,764, or 15%, over the prior year primarily due to inflationary effects on personnel costs, professional services, costs associated to operate and maintain the RNG facility and lower capitalized overheads. Personnel costs increased by approximately $1,094,000 due to increased staffing and the inflationary impact on salaries and benefits as well as awards of restricted stock. During fiscal 2023, no performance-based restricted stock was awarded, but was reinstated in fiscal 2024. Professional services expenses increased approximately $270,000 primarily due to increased external audit fees, actuarial services, recruiting costs and IT support. Further, costs associated with the RNG facility increased approximately $299,000, as the facility was only operational during seven months of the prior year as compared to all twelve months in the current year. Total capitalized construction overheads declined by approximately $429,000 compared to the prior year primarily due to a reduction in direct construction expenditures related to the RNG project, which was completed in fiscal 2023. Corporate insurance premiums accounted for much of the remaining cost increase.

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Taxes Other Than Income Taxes - Taxes other than income taxes increased by $370,338, or 16%, primarily due to higher property tax rates and growth in utility property, as well as increases in payroll taxes related to increased staffing and compensation.

Depreciation and Amortization - Depreciation and amortization expense increased by $753,416, or 8%, corresponding to a similar increase in net additions to depreciable utility property.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $1,766,881 associated with the recognition of AFUDC as a result of MVP construction activities continuing through May 2024. With the MVP in service, the Company now recognizes its share of operational earnings from the MVP, favorably adjusted for the amortization of a basis difference that arose when the Company recorded an other-than-temporary impairment of its investment in 2022. See Note 5 of the consolidated financial statements for additional information related to the MVP.

Other Income, Net - Other income increased by $382,233, or 59%, primarily due an increase of approximately $471,000 related to donations of certain natural gas distribution assets from a local housing authority.  Additionally, revenue sharing related to the asset management agreements increased by approximately $239,000. These increases were offset by an approximate $286,000 decrease in AFUDC related to the RNG facility, which was placed in service in March 2023, and approximately $62,000 less interest income.

Interest Expense - Total interest expense increased by $886,080, or 16%, primarily due to higher interest rates on the Company's variable rate debt and, to a lesser extent, higher borrowing levels. The weighted-average interest rate on the Company's total debt increased from 3.83% during fiscal 2023 to 4.27% during fiscal 2024, representing a 12% increase in the average rate. Total average debt outstanding during fiscal 2024 increased by 3% from fiscal 2023. Total borrowing levels were mitigated by equity issues through the ATM in fiscal 2024.

Roanoke Gas' interest expense increased by $484,454, or 15%, as total average debt outstanding increased by approximately $5,600,000 associated with net borrowings under the Company's line-of-credit. The average interest rate increased slightly from 3.51% in fiscal 2023 to 3.72% in fiscal 2024. All of Roanoke Gas' long-term debt carry fixed rates either due to fixed rate notes or with variable rate debt that has a corresponding swap agreement. See Note 6 and 7 of the consolidated financial statements for more information on the Company's debt.

Midstream's interest expense increased by $401,626, or 17%, as the average interest rate on Midstream's total debt increased from 4.32% to 5.21% related to higher interest rates on the variable rate credit facilities that were refinanced in 2024, net of an approximate $1,600,000 decrease in total average debt outstanding during the period.

The current interest rate environment may result in lower interest costs associated with the Company's variable rate debt.

Income Taxes - Income tax expense increased by $204,700, or 6%, corresponding to an increase in pre-tax income. The effective tax rate was 23.9% and 23.6% for fiscal 2024 and 2023, respectively. The effective tax rate is below the combined statutory state and federal rate due to the amortization of excess deferred taxes and tax credits. See Note 9 of the consolidated financial statements for the impact of tax credits on the effective tax rate.

Earnings Per Share and Dividends - Basic and diluted earnings per share were $1.16 in fiscal 2024 compared to $1.14 per share in fiscal 2023. Dividends declared per share of common stock were $0.80 in fiscal 2024 compared to $0.79 in fiscal 2023.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the impact of weather variability, the Company’s primary capital needs are the funding of its capital projects, the seasonal funding of its natural gas inventories and accounts receivables, debt service and payment of dividends to shareholders.  The Company anticipates funding these items through its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock.

Cash and cash equivalents decreased by approximately $618,000 in fiscal 2024 compared to $3.4 million in fiscal 2023. The following table summarizes the categories of sources and uses of cash:

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Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas distribution business causes operating cash flows to fluctuate significantly during the year, as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash flows from operating activities decreased by $6.4 million from the prior year. The table below summarizes the significant components operating cash flow:

The decline in operating cash flows is primarily due to the reduction in the value of gas withdrawn from storage. The average price of gas in storage during fiscal 2023 was more than $6.00 per DTH compared to approximately $4.00 per DTH during the current fiscal year. The decrease in the unit cost of gas in storage was attributable to much lower commodity prices during last year's summer storage injections as compared to fiscal 2022.  Accordingly, as lower-priced gas was withdrawn from storage during fiscal 2024, cash flow levels were reduced when compared to fiscal 2023. Additionally, though the SCC issued its final order in December 2023, Roanoke Gas implemented interim billing rates in January 2023; therefore, the Company began accruing an estimated rate refund representing the amount due customers for the difference between total customer billings at interim rates versus total customer billings at final rates. Upon SCC approval of final rates, Roanoke Gas issued refunds in February 2024 to all customers that were billed at interim rates since January 2023. When compared to the prior year, the distribution of the rate refund to customers reduced cash available for operations by $1.3 million.

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to Roanoke Gas' utility property, 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.  Roanoke Gas' expenditures were approximately $22.1 million and $25.3 million in fiscal 2024 and 2023, respectively. The $3.2 million decrease in expenditures is primarily due to higher prior-year investment for the RNG project, which was placed in service in March 2023. Roanoke Gas renewed 5.4 miles of main and 412 service lines and 5.7 miles of main and 452 service lines in fiscal years 2024 and 2023, respectively. With the recent approval of its new SAVE Plan and Rider, the Company is continuing its focus on SAVE infrastructure replacement projects, including the replacement of pre-1973 first generation plastic pipe. New customer demand for natural gas continues to be strong and therefore extending the natural gas distribution system within its service territory is also a priority. Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 521 customers in fiscal 2024, compared to 430 customers in fiscal 2023.

Capital expenditures are expected to be approximately $22 million annually over the next few years as Roanoke Gas continues to focus on its SAVE Plan, as well as system improvements and customer growth. The Company expects to utilize its operating cash flows and credit facilities, as well as to consider additional long-term debt and equity capital, to meet the funding requirements of these planned expenditures.

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Investing cash flows also reflects the fiscal 2024 funding of approximately $18,000 for Midstream's participation in the LLC, down from the $2.1 million in fiscal 2023.  Midstream ceased future participation in capital calls following its May 2023 funding payment based on an agreement with the LLC's managing partner. Midstream continues to be invested in the LLC; however, its ownership percentage declined as it did not make additional investments. Now that the MVP is in service, Midstream will incur normal periodic capital investment related to ongoing MVP operations requirements and system improvements, in which it will again participate. Midstream has and will continue to make capital investments in Southgate. The targeted timing for completion of the Southgate project is 2028.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of common stock and the payment of dividends. Net cash flows provided by financing activities were approximately $4.0 million and $200,000 in fiscal 2024 and 2023, respectively.  The $3.8 million increase in financing cash flows is primarily attributable to net borrowings of $6.8 million under Roanoke Gas' line-of-credit during fiscal 2024 compared to $4.3 million in net borrowings in the prior year. Additionally, Midstream borrowed a net amount of $680,000 during fiscal 2024 from its amended credit facility compared to net repayments of approximately $196,000 in the prior year.  During fiscal 2024, the Company realized $4.7 million from the issuance of 234,645 shares through the ATM program and DRIP activity compared to $3.9 million received from the issuance of 194,719 shares from those same activities, as well as the exercise of stock options, during the prior year.  Cash outflows for dividend payments were $8.0 million as the annualized dividend rate increased from $0.79 to $0.80 per share and total outstanding shares increased as a result of the stock issuance activity. The Company’s consolidated capitalization was 44.1% equity and 55.9% long-term debt at September 30, 2024, exclusive of unamortized debt expense. This compares to 44.4% equity and 55.6% long-term debt at September 30, 2023.

The current interest rate environment may result in lower interest costs associated with the Company's variable rate debt.

Management regularly evaluates the Company’s liquidity through a review of its available financing resources and its cash flows. Resources maintains the ability to raise equity capital through its ATM program, private placement or other public offerings. Management believes Roanoke Gas has access to sufficient financing resources to meet its cash requirements for the next year, including the line of credit and the two private shelf facilities. The first shelf facility provides for the issuance of up to $40 million in unsecured notes in addition to the $28 million previously issued.  This shelf agreement is scheduled to expire on December 6, 2025.  The second facility provides for the issuance of up to $70 million in unsecured notes during its current term, which expires September 30, 2025.

Roanoke Gas may also adjust capital spending as necessary, if such a need would arise. With the MVP now in service, Midstream's future cash requirements will relate to regular monthly operating expenses, debt service and capital contributions. The Company received its first cash distribution from MVP of approximately $800,000 in October 2024, and should receive similar distributions quarterly. On March 6, 2024, Midstream refinanced its Promissory Notes with one lender, increased the capacity of its $23 million credit facility to $25 million and extended the maturity date to December 31, 2025. Further, on May 2, 2024, Midstream established a new $9 million line of credit facility that matures on May 2, 2026. With these proceeds, Midstream paid in full the $9 million balance on its note payable that matured on June 1, 2024. With the extension of its original credit facility and the establishment of the new credit facility, Midstream's total debt repayment over the succeeding 12 months is $800,000 in principal payments. Management believes that it will be able to meet Midstream's cash requirements over the ensuing 12-month period with its quarterly cash distributions from MVP.

Notes 6 and 7 of the consolidated financial statements provide details on the Company's line-of-credit and borrowing activities.

ATM Program

Resources issued 129,164 shares of common stock for $2,635,200, net of $67,569 in fees, under the ATM program for the year ended September 30, 2024.  For the year ended September 30, 2023, Resources issued 127,852 shares of common stock for $2,713,020, net of $69,565 in fees, under the ATM program.

Off-Balance Sheet Arrangements

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

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Equity Investment in Mountain Valley Pipeline

Midstream owns a less than 1% equity investment in the LLC that owns and operates the MVP.  The Company accounts for its interest in the LLC under the equity method of accounting given the LLC maintains specific ownership accounts for each investor, and also considering the Company's rights under the LLC management agreement and the Company's involvement as a customer of the MVP.  The Company has been using the equity method since the inception of its investment in fiscal 2016.  Following receipt of authorization from the FERC, the MVP entered commercial operation on June 14, 2024 and became available for interruptible or short-term firm transportation service.  On July 1, 2024, the MVP commenced long-term firm capacity obligations.  Midstream is also a less than 1% investor, accounted for under the cost method, in Southgate, which is in the design and permitting phase.  Completion of the Southgate pipeline is targeted for June 2028.

From inception through May 2024, earnings from the LLC were primarily attributable to AFUDC income. With the MVP now in operation, the Company recognizes its share of earnings from the LLC, favorably adjusted for a basis difference between the Company's proportional share of assets and its carrying value that arose when the Company recorded an other-than-temporary impairment of its investment in 2022. This basis difference amortization is a favorable non-cash adjustment over the operational life of the MVP, or 40 years. For fiscal 2024 and 2023, the Company recorded equity in earnings of consolidated affiliates of $3.9 million and $2.1 million, respectively, which included $3.0 million and $2.1 million from AFUDC. The Company participates in quarterly cash distributions by the LLC, the first of which was in October 2024. The Company's share was approximately $800,000.

Regulatory

See Note 4 of the consolidated financial statements for discussion on Regulatory matters.

Critical Accounting Estimates

The consolidated financial statements of Resources are prepared in accordance with GAAP. 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 management 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 ASC 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.

Unbilled revenue recognition - The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,294,798 and $1,240,097 as of September 30, 2024 and 2023, respectively. Because the process is performed monthly, the Company routinely ensures its methodology continues to provide a reasonable estimate.

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Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 12 of 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.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporates the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 4.83% for valuing both its pension plan and postretirement plan liabilities at September 30, 2024. These discount rates represent a decrease from the 5.63% for the pension plan and postretirement plan used for valuing the corresponding liabilities at September 30, 2023. The decrease in discount rates reflect the Federal Reserve's easing of interest rates in 2024 and general long-term rate decline.  The yield on the 30-year Treasury increased from 3.79% at September 30, 2022 to 4.73% at September 30, 2023 and decreased to 4.14% at September 30, 2024. Corporate bond rates experienced a smaller increase as credit spreads have narrowed. The rise in the discount rates through 2023 was the primary factor in the reduction of the benefit obligations for both the pension and the postretirement plan. Mortality assumptions were based on the PRI-2012 Mortality Table with improvements projected generational using Projection Scale MP-2021 for the current year valuation.

The Company has focused on minimizing the financial risk associated with these plans. With the soft freezes of both the pension and postretirement plans, future liability growth associated with participant service and compensation has been limited.  Since January 2017, when the pension plan froze access to new employees, the asset allocation has transitioned from 60% equity and 40% fixed income to 25% equity and 75% fixed.  During the same period, the fixed income portion of the plan was transitioned to an LDI approach, with the fixed income assets invested in securities with a duration that corresponds to the duration of the corresponding liability.  This synchronization of the pension assets with the pension liabilities has reduced volatility in the funded status of the plan.  This is evidenced by the relative stability of the funded status of the pension plan at September 30, 2024 and 2023 with a funded ratio of 104% and 100%, respectively.  The 25% allocation to equity investments provides asset growth potential to offset increases in the pension liability related to those employees continuing to accrue benefits. Management will continue to evaluate the investment allocation as the liabilities mature and make adjustments as necessary.

The Company has initiated a transition of the postretirement plan assets from a 50% equity and 50% fixed income allocation to a 30% equity and 70% fixed income allocation.  This revision to the investment targets is in response to a greater proportion of participants that have transitioned to retirement.  Similar to the pension plan, the revision to the asset allocation will seek to reduce the volatility in funded status while still providing the opportunity for asset growth through the equity portion of the portfolio.  The funded status for the postretirement plan was 139% and 116% as of September 30, 2024 and 2023, respectively.  The improvement in the funded status was due to stronger-than-expected market performance only partially offset by higher liabilities as the Company is effectively matching durations within the portfolio.  Management will continue to monitor and evaluate the asset allocation and adjust as warranted.

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

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The Company annually evaluates the long-term rate of return on its targeted investment allocation model, as well as the overall asset allocation of its benefit plans, and reviews both plans' potential long-term rate of return assumptions with its investment advisors to determine the rates used in each plan's actuarial calculations. The long-term rates of return increased slightly from 4.50% in fiscal 2024 to 4.95% for fiscal 2025 for the pension plan and from 4.21% in fiscal 2024 to 4.95% for fiscal 2025 for the postretirement plan. Management will continue to evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that the Company will have no minimum funding requirements next year.  The Company currently does not expect to make contributions to its pension plan and postretirement plan in fiscal 2025 due to the funded position of the plans. 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.

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.

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of ASC 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 four interest-rate swaps outstanding at September 30, 2024 related to its variable rate notes.  The corresponding fair value of these swaps is reflected on the consolidated balance sheets as of September 30, 2024 and 2023.  A 25 basis point decrease and increase on the yield curve would result in a $228,248 decrease and $226,748 increase, respectively, in the fair value of the interest rate swaps on the balance sheet. See Notes 1 and 8 to the consolidated financial statements for additional information regarding the swaps.

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,200 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary.  Midstream, a wholly-owned subsidiary of Resources, is a less than 1% investor in the MVP and Southgate, respectively. More information regarding the investment in MVP is provided below and under the Equity Investment in Mountain Valley Pipeline section.

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Following extended periods of delay due to actions by the Fourth Circuit, Congress passed and the President signed into law legislation to expedite the completion of the MVP.  The Fourth Circuit continued to stay the necessary permits to complete the pipeline.  Following a petition filed by the LLC to request relief from the stays issued by the Fourth Circuit, on July 27, 2023, the SCOTUS granted the relief requested and vacated the stays.  Construction on the MVP resumed immediately and completion is currently expected during the first quarter of calendar 2024.

The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions and rates charged to customers for natural gas service, safety standards, extension of service and depreciation. Nearly all of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates and fees authorized by the SCC. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.  These rates are determined based on various rate applications filed 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 in place at that time.  The investment in replacing and upgrading existing infrastructure, as well as recovering increases in non-gas expenses due to inflationary pressures, regulatory requirements or operation needs, are generally not recoverable until a formal rate application is filed to include additional investment and higher costs, and new non-gas base rates are approved.

The Company is also subject to regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines, as well as the FERC, which regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.

Beginning January 1, 2023, Roanoke Gas implemented new, non-gas base rates designed to provide $8.55 million in additional annual non-gas revenues in response to higher operating costs and to recover its investment in non-SAVE related projects since the last non-gas base rate increase in fiscal 2019.  Revenues from the SAVE Plan and Rider were incorporated into the new non-gas base rates.  In September 2023, Roanoke Gas and SCC staff reached a settlement agreement for $7.45 million in additional annual non-gas revenues pending final approval by the SCC.  Roanoke Gas placed the new non-gas base rates into effect on October 1, 2023 and has established a reserve for the difference between the rates implemented on January 1, 2023 and the new rates in the settlement agreement.  The excess revenues collected will be refunded to customers upon receipt of the final SCC order, which is expected to be received in late calendar 2023 or early 2024.

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 to customer bills and 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, RNG and PGA.

The SAVE Plan and Rider provides the Company with a mechanism through which it recovers costs related to SAVE qualified infrastructure investments on a prospective basis, until such time a formal rate application is filed incorporating these investments in non-gas base rates.  The SAVE Plan and Rider reset effective January 1, 2023, when the recovery of all prior SAVE Plan investment was incorporated into the new non-gas base rates, and accordingly, SAVE Plan revenue decreased by approximately $2,182,000 from the prior year.  Roanoke Gas filed and received approval from the SCC for a new SAVE Plan and Rider with new rates placed into effect on October 1, 2023 that will result in approximately $366,000 in SAVE related revenues during fiscal 2024.  Additional information regarding the SAVE Plan and Rider is provided under the Regulatory section below.

The WNA mechanism 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 a level of price protection when the weather is colder than normal. The WNA allows the Company to recover from customers the lost margin, excluding gas costs, from the impact of warmer than normal weather and correspondingly requires the Company to refund to customers the excess margin earned for colder than normal weather.  The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day and thereby estimates the revenue adjustment based on weather variance from normal.  Any billings or refunds related to the WNA are completed following each WNA year, which extends for the 12-month period from April to March. The Company recorded approximately $3,005,000 and $1,973,000 in additional revenues under the WNA for weather that was approximately 16% and 13% warmer than normal for the fiscal years ended September 30, 2023 and 2022, respectively.  The number of heating degree days used to determine normal can change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding warmer than normal years to replace colder years, the number of heating degree days that defines normal has trended downward over the last several years.

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The Company also has an approved rate structure that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue by applying the ICC factor, based on the Company’s weighted-average cost of capital, including interest rates on short-term and long-term debt, and the Company’s authorized return on equity, to the average cost of natural gas inventory during the period.  Total ICC revenues increased from approximately $657,000 in fiscal 2022 to $967,000 in fiscal 2023 as a result of the higher cost of gas in storage at the beginning of the fiscal year.  Monthly average inventory balances, used to calculate ICC revenues, increased by 46%.  However, as natural gas commodity prices declined significantly during the summer storage injection period, the average price of gas in storage at September 30, 2023 declined by 37% compared to the same period last year.  Accordingly, fiscal 2024 ICC revenues are expected to decline from current year levels.

In March 2023, Roanoke Gas began the operation of the RNG facility to produce commercial quality RNG for delivery into its distribution system through a cooperative agreement with the Western Virginia Water Authority.  With SCC approval, Roanoke Gas is allowed to recover the costs associated with the investment in RNG facilities and related operating costs through an RNG Rider added to customer bills.  The customer benefits from this program through the monetization of environmental credits generated through RNG production, in which these credits are returned to customers through the RNG Rider.  See the Regulatory section below for more information on RNG.

The cost of natural gas is a pass-through cost and is independent of the Company's non-gas rates. Accordingly, the Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs through a quarterly filing (or more frequent if necessary) with the SCC. Once SCC approval is received, the Company adjusts the gas cost component of its rates.  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.

Cyber Risk

Cyber attacks are a constant threat to businesses and individuals. The Company remains focused on these threats and is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information, as well as important operational and financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management continuously monitors access to these systems and believes it has security measures in place to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial costs that may result from a cyber incident.

Inflation and Rising Prices

Natural gas commodity, delivery and storage capacity costs constitute the single largest expense of the Company, representing 65% of fiscal 2023 total operating expenses.  After peaking in December 2022, natural gas commodity prices decreased significantly through the remainder of fiscal 2023.   The decline in prices was primarily due to improved supply availability resulting from a warm winter season.  Roanoke Gas recovers natural gas costs through the PGA mechanism as noted above; however, in times where commodity prices rapidly increase, the timing of recovery may lag.  Increasing natural gas prices, especially in relation to other energy options, may lead to reductions in energy consumption through customer conservation or fuel switching in addition to the potential for higher bad debts related to customers' inability to pay higher natural gas bills.

Inflation, due to supply chain delays, labor shortages and limited availability of critical supplies among other factors, affects the Company through increases in non-gas expenses such as labor, employee benefits, materials and supplies, contracted services, corporate insurance and other areas.  The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas base rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas base rate application can result in an inherent lag in non-gas expense recovery.  Therefore, authorized non-gas base rates may not keep pace with rising costs during inflationary periods.  Management regularly evaluates the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas base rate adjustment. Accordingly, management filed a non-gas rate application in early December 2022 to incorporate increased expense levels and additional rate base, including both SAVE and non SAVE related plant investment, since the last non-gas base rate application.  These new non-gas base rates were implemented effective January 1, 2023 subject to refund.  See the Regulatory section below for more information.

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Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which are primarily associated with the utility segment. Additional segment analysis is provided when Midstream's investment in affiliates represents a significant component of the comparison.  Net income increased by $43,031,884 from a net loss position of $31,732,602 to net income of $11,299,282 primarily due to the impairment of the Company's LLC investment in fiscal 2022 and the implementation of new non-gas base rates in January 2023.  Excluding the after-tax effect of the prior year's impairment, net income would have increased by approximately $2,120,000.

The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated statement of income under the line item cost of gas - utility. The cost of natural gas, 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, is passed through to customers at cost.  Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. The following results of operations analyses will reference gross utility margin.

Fiscal Year 2023 Compared with Fiscal Year 2022

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

Total gas utility operating revenues for the year ended September 30, 2023 increased by 16% from the year ended September 30, 2022 primarily due to higher natural gas commodity prices during the first half of fiscal 2023, the implementation of a non-gas base rate increase, net of a reduction in SAVE revenues, higher ICC revenues and the implementation of the RNG Rider, slightly offset by lower deliveries due to warmer weather.  Natural gas commodity prices for fiscal 2023 purchases declined from the prior year by approximately 9% per DTH; however, the total commodity component of gas costs increased by 37% per DTH due to the withdrawal of higher priced storage gas during the winter heating season.  Total gas costs, which includes pipeline and storage fixed demand costs, increased by 26% compared to the same period last year, which corresponded to the 21% per DTH increase in the gas cost component of revenue.  The non-gas base rate increase implemented in January 2023 contributed to an approximate $3.0 million increase in non-gas volumetric revenues, net of lower delivered volumes, and $1.2 million increase in customer base charge revenue.  SAVE revenues declined due to the inclusion of the cumulative SAVE investment in the new non-gas base rates.  As discussed in the Overview section, the SAVE Plan and Rider were temporarily halted with the implementation of the new rates.  Corresponding to the higher average price of natural gas in storage during the first half of fiscal 2023, ICC revenues rose 47%.  Additionally, the operation of the new RNG facility has added a new revenue stream for the Company.  Residential and commercial deliveries decreased by 3% corresponding to a comparable decline in heating degree days, while transportation and interruptible volumes, primarily driven by business activity rather than weather, increased by 1%.

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Gross utility margin increased over the prior fiscal year primarily as a result of the implementation of higher non-gas base rates, net of the reduction in SAVE revenues, combined with higher ICC revenues and the addition of RNG revenues. The reduction in the higher margin residential and commercial volumes, due to a warmer heating season, was mitigated by the WNA mechanism that provided for the recovery of lost margin related to the warmer weather.

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

Operations and Maintenance Expense - Operations and maintenance expense increased by $414,732, or 3%, over the prior year primarily due to increases in compensation costs, contracted services, corporate insurance premiums and RNG expenses, net of greater capitalized overheads and lower bad debt expense.  Compensation costs and contracted services increased by approximately $852,000 due to increased staffing and the effects of inflation on salaries and externally provided services.  Corporate insurance premiums increased by approximately $164,000 due to insurance market conditions and higher coverage limits.  The operation of the new RNG facility contributed approximately $151,000 in additional operating expense.  Total capitalized overheads increased by approximately $272,000 due to a combination of higher levels of constructed assets and a higher capitalization rate, as well as increased LNG production.  Bad debt expense decreased by approximately $445,000 as customer and payment activity returned to historical, pre-COVID patterns resulting in improved aging and lower write-offs.

General Taxes - General taxes increased by $39,111, or 2%, due to increases in property taxes on greater utility plant investment and higher payroll taxes on increased employee count and compensation.

Depreciation - Depreciation expense increased by $815,755, or 9%, corresponding to a similar increase in net additions to depreciable utility property.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment increased by $2,011,663 related to the recognition of AFUDC as construction activities on the MVP resumed in June 2023.  See the Equity Investment in Mountain Valley Pipeline section below for additional information.

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Impairment of Unconsolidated Affiliates - The $55,092,303 impairment was due to two other-than-temporary write-downs of the Company's investment in the LLC that were made during the second and fourth quarters of fiscal 2022 as a result of the Company's valuation assessment during the prior year.  See Equity Investment in Mountain Valley Pipeline and Critical Accounting Policies and Estimates sections below for more information.

Other Income, Net - Other income decreased by $810,455, or 56%, primarily due to an approximate $1,502,000 increase in the non-service cost components of net periodic benefit costs arising from the effect of much higher interest rates on the actuarial expense calculation.  This was partially offset by an approximate $227,000 increase in AFUDC recognized on the RNG project, $169,000 in additional interest income due to higher interest rates on available cash and $231,000 in additional revenue sharing based on the revised agreement with the Company's asset manager.

Interest Expense - Total interest expense increased by $1,120,876, or 25%, primarily due to higher interest rates on the Company's variable rate debt and, to a lesser extent, higher borrowing levels.  The weighted-average interest rate on the Company's total debt increased from 3.06% during fiscal 2022 to 3.83% during fiscal 2023, representing a 25% increase in the average rate.  Total average debt outstanding during fiscal 2023 increased by less than 1% from fiscal 2022.  Total borrowing levels were mitigated by the residual proceeds from the fiscal 2022 equity offering and the subsequent equity issues through the ATM in fiscal 2023.

Roanoke Gas' interest expense increased by $214,294, or 7%, as total average debt outstanding increased by approximately $2,500,000 associated with net borrowings under the Company's line-of-credit.  The average interest rate increased slightly from 3.38% in fiscal 2022 to 3.51% in fiscal 2023.  All of Roanoke Gas' long-term debt carry fixed rates either due to fixed rate notes or with variable rate debt that has a corresponding swap agreement.  See Note 6 and 7 for more information on the Company's debt.

Midstream's interest expense increased by $906,582, or 61%, as the average interest rate on Midstream's total debt increased from 2.59% to 4.32% related to rising interest rates on the variable rate credit facility, net of an approximate $1,900,000 decrease in total average debt outstanding during the period.

Income Taxes - Income tax expense increased by $14,902,556, moving from a tax benefit of $11,410,645 in fiscal 2022 to tax expense of $3,491,911 in fiscal 2023.  The net tax benefit in fiscal 2022 was attributable to a net deferred tax benefit of $14,180,759 corresponding to the recognition of the impairment of the Company's investment in the LLC. The effective tax rate was 23.6% for fiscal 2023 compared to 26.5% for fiscal 2022. The effective tax rate for the prior fiscal year exceeded the combined federal and state statutory rate of 25.74% due to the combination of moving to a taxable loss position combined with deductions related to the amortization of the R&D tax credits. Excluding the impairment, the effective tax rate for fiscal 2022 would have been 23.2%.  See Note 8 for the impact of tax credits on the effective tax rate.

Earnings Per Share and Dividends - Basic and diluted earnings per share were $1.14 in fiscal 2023 compared to $3.48 loss per share in fiscal 2022. Dividends declared per share of common stock were $0.79 in fiscal 2023 compared to $0.78 in fiscal 2022.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the impact of weather variability, the Company’s primary capital needs are the funding of its capital projects, investment in the LLC, the seasonal funding of its natural gas inventories and accounts receivables, debt service and payment of dividends to shareholders.  The Company anticipates funding these items through its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock.

Cash and cash equivalents decreased by approximately $3.4 million in fiscal 2023 compared to a $3.4 million increase in fiscal 2022. The following table summarizes the categories of sources and uses of cash:

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Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas distribution business causes operating cash flows to fluctuate significantly during the year, as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash flows from operating activities increased by $8.2 million from the prior year. The table below summarizes the significant components operating cash flow:

The primary driver for the increase in operating cash flows was the change in gas storage balance.  During the fiscal 2022 summer storage refill period, which generally extends from March through October, natural gas commodity prices rose significantly with the average price of gas in storage increasing from $3.15 per DTH at September 30, 2021 to $7.02 per DTH at September 30, 2022, resulting in a $9 million use of operating cash.  Subsequently, in fiscal 2023, much of the higher priced gas was withdrawn from storage to meet the energy demands of the winter heating season. When the fiscal 2023 summer storage refill period began, natural gas commodity prices were much lower than the prior fiscal period resulting in a decline in the average price of gas in storage to $4.40 per DTH at September 30, 2023, thereby generating $5.7 million in operating cash in fiscal 2023.  This improvement in operating cash flow was mitigated by changes in supplier refunds and under-collection of gas costs.  In March 2022, the Company received a $2.3 million supplier refund, resulting from a FERC rate case settlement, from one of the interstate pipelines that provides the Company with natural gas.  In July 2022, the Company began refunding this balance, along with other smaller refunds, to customers over a 12-month period.  The transition from collecting supplier refunds in fiscal 2022 to refunding them during fiscal 2023 resulted in a $4.7 million net reduction in operating cash between years.   At September 30, 2021, Roanoke Gas was in a net under-collected gas cost position of more than $5 million due to timing in adjusting the PGA factor for rising gas costs.  During fiscal 2022, Roanoke Gas collected from customers, through the ACA mechanism, nearly $3.6 million of the prior year under-collection.  In fiscal 2023, Roanoke Gas collected the remaining $1.4 million through the ACA mechanism; however, Roanoke Gas also generated a $1.5 million under-collection associated with current year gas costs.  As a result of the aforementioned lower gas costs and the application of the supplier refunds to customers' accounts, as well as reduced delinquent balances, accounts receivable moved from a $500,000 use of cash in fiscal 2022 to a $1.4 million source of operating cash in fiscal 2023.  The impairments on the Company's investment in the LLC resulted in significant swings in net income, deferred taxes and the recognition of impairment charges; however, the net effect of the impairments did not have an impact to operating cash flow.

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Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility property, 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 Midstream's investment in the LLC.  Roanoke Gas' expenditures were approximately $25.3 million and $25.5 million in fiscal 2023 and 2022, respectively. Roanoke Gas renewed 5.7 miles of main and 452 service lines and 8.3 miles of main and 605 service lines in fiscal years 2023 and 2022, respectively. The current SAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe in addition to other SAVE related infrastructure. Furthermore, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 430 customers in fiscal 2023, compared to 544 customers in fiscal 2022.  The RNG project, which went into service in March 2023, also accounted for $3.9 million and $3.1 million in expenditures for fiscal 2023 and 2022, respectively.  Depreciation covered approximately 39% and 36% of the current and prior year's capital expenditures, respectively, with the balance provided from other operating cash flows and financing activities.

Capital expenditures are expected to be at least $20 million annually over the next few years as Roanoke Gas continues to focus on its SAVE Plan, as well as system improvements and customer growth. The Company expects to utilize its operating cash flows and credit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflects the fiscal 2023 funding of $2.1 million for Midstream's participation in the LLC, down from the $5.3 million in fiscal 2022.  Effective in May 2023, under agreement with the LLC's managing partner and primary interest owner, Midstream's future capital contributions to the LLC have been assumed by the primary interest owner.  Accordingly, Midstream has no further capital contributions during the remaining construction period of the MVP.  Midstream has and will remain responsible for its portion of the capital requirements of the Southgate project.  The LLC's managing partner is currently targeting completion of the MVP during the first quarter of calendar 2024. More information is provided under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of common stock and the payment of dividends. Net cash flows provided by financing activities were $200,000 and $18.4 million in fiscal 2023 and 2022, respectively.  The decrease in financing cash flows was primarily attributable to Resources' $27 million equity offering in March 2022 of which $12 million was invested in Roanoke Gas and $10 million in Midstream.  The remaining $5 million in equity was invested in Midstream in fiscal 2023.  Due to these cash infusions from the equity issue and the issuance of Roanoke Gas' $15 million and $10 million unsecured notes and Midstream's $8 million note, Roanoke Gas was able to pay down its line-of-credit balance and maturing $7 million note and Midstream applied $18 million against its non-revolving credit facility during fiscal 2022.  During fiscal 2023, the Company realized $3.9 million from the issuance of stock through the ATM program, DRIP activity and the exercise of stock options compared to the $2.0 million received from those same activities during the prior year, in addition to the $27 million from the equity offering.  Cash out flows for dividend payments reached $7.8 million as the annualized dividend rate increased from $0.78 to $0.79 per share and total outstanding shares increased as a result of the stock activity. The Company’s consolidated capitalization was 44.4% equity and 55.6% long-term debt at September 30, 2023, exclusive of unamortized debt expense. This compares to 40.4% equity and 59.6% long-term debt at September 30, 2022.

The current interest rate environment is expected to continue to result in higher interest costs associated with the Company's variable rate debt or on the issuance of any new debt.

Management regularly evaluates the Company's liquidity through a review of its available financing resources and its operating cash flows.  Resources maintains the ability to raise equity capital through its ATM program, private placement or other public offerings.  Management believes Roanoke Gas has sufficient financing resources to meet its cash requirements for the next year, including the line-of-credit and the two private shelf facilities.  The first shelf facility provides for the issuance of up to $40 million in unsecured notes in addition to the $28 million previously issued.  This shelf agreement was extended in December 2022 and is scheduled to expire on December 6, 2025.  The second facility provides for the issuance of up to $70 million in unsecured notes during its current term, which expires September 30, 2025.  Roanoke Gas may also adjust capital spending as necessary if such a need would arise.

Based on the agreement with the LLC's managing partner to assume future capital contributions related to the MVP, Midstream's future cash requirements are reduced to regular monthly operating expenses, debt service and capital contributions to Southgate.   Midstream's total debt service over the succeeding 12 months includes $11 million to retire maturing debt and approximately $2.7 million in interest expense based on current rates.  With current projections by the LLC's managing partner of MVP completion date during the first quarter of calendar 2024 and the subsequent operation of the pipeline, management believes that they will be able to negotiate extensions or refinancing options on the maturing debt and Midstream will meet its cash requirements over the ensuing 12 month period.

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Notes 6 and 7 provide details on the Company's line-of-credit and borrowing activities.

ATM Program

Resources issued 127,852 shares of common stock for $2,713,020, net of $69,565 in fees, under the ATM program for the year ended September 30, 2023.  For the year ended September 30, 2022, Resources issued 4,872 shares of common stock for $112,500, net of $2,813 in fees, under the ATM program.

Off-Balance Sheet Arrangements

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

Equity Investment in Mountain Valley Pipeline

The Company has a less than 1% interest in the MVP, which is accounted for as an equity investment, and a less than 1% interest in the Southgate pipeline, which is contemplated to interconnect with the MVP.  As discussed more fully in Note 5, since inception, the MVP has encountered various legal and regulatory issues that have substantially delayed the completion of the project, including a period in 2022 where work on the project had been halted.

As required by GAAP, management assesses the fair value of its investment on a quarterly basis.  As a result of the halt in construction in 2022, management conducted an assessment of its investment in MVP in accordance with the provisions of ASC 323, Investments - Equity Method and Joint Ventures. This assessment included a third-party valuation.  As a result of its evaluations, management concluded that the investment in the LLC sustained other-than-temporary declines in fair value and recorded pre-tax impairment losses of $39.8 million and $15.3 million in its second and fourth quarters of 2022, respectively. This is described more fully in Note 5.

Developments in 2023 on the legislative and legal fronts were favorable.  Most notably, in June 2023, the FRA declared the completion of the MVP to be in the national interest and cleared the permitting and regulatory impediments.  It also divested courts of jurisdiction to review agency actions on approvals necessary for MVP construction and initial operation.  In July 2023, SCOTUS lifted certain stays and cleared the judicial impediments.  Construction work restarted and the current target is that the MVP will be completed in the first quarter of calendar 2024.  Combined, these actions have significantly increased the Company’s assessment of the probability of a successful project with a concomitant increase to fair value.  GAAP does not permit the Company to reverse previously recorded impairment charges.

To date, Resources' earnings from MVP are primarily attributable to AFUDC income generated by the LLC.  Once the pipeline is commercially operational, AFUDC will cease and the Company will begin to receive its share of LLC earnings from long-term contracts to provide gas that were previously executed by the LLC.  Resources expects cash distributions from the LLC to begin three to six months after commercial operations begin.

Although the outlook for the MVP project is more positive than a year ago, management will monitor the status of MVP and Southgate for circumstances that could lead to future impairments. The amount and timing of further impairment, if any, would be dependent on the specific circumstances, including changes to probabilities of completion, changes in the assumed future cash flows and discount rate at the time of evaluation.

Midstream fully borrowed $23 million under its non-revolving credit facility, which matures in December 2024.  It has begun amortization of $400,000 per quarter on an additional variable rate note, as well as a note that comes fully due in June 2024.  The Company is actively discussing and anticipates refinancing those obligations in 2024.  With the expected completion of MVP in the first quarter of calendar 2024, Midstream is considering the long-term structure of its debt as it evolves from a project phase to an operating phase.  See Note 7 for more information on all borrowings related to Midstream.

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Regulatory

On December 2, 2022, Roanoke Gas filed an application with the SCC seeking an $8.55 million annual increase in its non-gas base rates, of which $4.05 million was being recovered through the SAVE Rider.  Since the Company was seeking to recover the costs associated with its SAVE Plan through interim non-gas base rates effective January 1, 2023, the Company discontinued its SAVE Plan and Rider for the remainder of the current fiscal year.  In the fourth quarter of fiscal 2023, the Company reached a settlement with the SCC staff on all outstanding issues in the case.  Under the terms of the settlement, the Company agreed to an incremental revenue requirement of $7.45 million. The Company agreed to begin billing the new rates effective October 1, 2023.  The Company expects to receive the final order on the rate application in late calendar 2023 or early 2024.

The Company has recorded a provision for refund, including interest, associated with customer billings for the difference between the interim rates and the settlement rates.

Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Rider. The Company filed an application with the SCC for a new, five-year SAVE Plan and Rider on March 31, 2023, seeking recovery of costs associated with an estimated $8.5 million in SAVE eligible investment in fiscal 2024 and an estimated cumulative investment of $49.5 million over the proposed five-year plan period ending September 30, 2028.  On August 31, 2023, the SCC approved the new SAVE Plan and Rider with rates effective October 1, 2023.

On May 16, 2022, Roanoke Gas announced a cooperative agreement under which Roanoke Gas and the Western Virginia Water Authority would produce commercial quality RNG from biogas produced at the regional water pollution control plant.  In August 2022, Roanoke Gas filed an application with the SCC seeking approval of a rate adjustment clause to recover the costs associated with constructing, owning, operating and maintaining the renewable natural gas facility.  The application was filed under Chapter 30 of Title 56 of the Code of Virginia.  Chapter 30 allows the Company to accrue AFUDC on the RNG project.  In connection with the RNG project, Roanoke Gas began accruing AFUDC in fiscal 2022 associated with construction of the facility.  The Company has recognized approximately $468,000 of AFUDC since inception of the RNG project.  The Company received a final order from the SCC on January 23, 2023 approving the Company’s application. The RNG facility became operational in March 2023.  The Company began billing customers the RNG rate adjustment on March 1, 2023, at which time the Company ceased recording AFUDC.

On May 30, 2023, the Company filed an application with the SCC to update the RNG Rider with an effective date of October 1, 2023.  On September 1, 2023, the SCC approved the updated RNG Rider with rates effective October 1, 2023.

On June 2, 2022, Roanoke Gas filed an application with the SCC to acquire certain natural gas distribution assets from a local housing authority.  Under this application, the Company requested the approval to acquire such facilities at five separate apartment complexes, located in the Company’s service territory, that were under housing authority management.  Under the proposed plan, the housing authority would renew existing natural gas distribution facilities to include mains, services, and meter installations and then transfer ownership of these facilities to Roanoke Gas.  In turn, Roanoke Gas would assume responsibility for the operation and maintenance of these assets and recognize a gain related to the asset acquisition equal to the cost associated with the renewal.

On July 19, 2022, the SCC approved the application and on August 4, 2022, the housing authority transferred the assets from two apartment complexes to Roanoke Gas. Roanoke Gas recorded these assets and recognized a pre-tax gain of approximately $219,000 during the fourth quarter of fiscal 2022.  On September 29, 2023, the housing authority transferred the assets from one additional apartment complex to Roanoke Gas and the Company recorded a pre-tax gain of approximately $311,000 during the fourth quarter of fiscal 2023.  The authority is awaiting future funding to complete the two remaining apartment complexes.  The timing of funding and the completion of the asset renewals for these complexes is unknown at this time.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with GAAP. 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 management and professional judgments. Actual results may differ significantly from these estimates and assumptions.

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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.

Investments - Under the provisions of ASC 323, Investments - Equity Method and Joint Ventures, the Company is required to evaluate its investment in the LLC to determine if the fair value of the investments are below the carrying amount and if this decline in fair value is considered other-than-temporary.  If the results of the evaluation indicate that the decline in fair value is other-than-temporary, then the recognition of an impairment is required. The following events or circumstances would indicate the potential of an other-than-temporary decline in the fair value of the investment in the LLC:

• a prolonged period of time that the fair value is below the investor’s carrying value;

• the current expected financial performance is significantly worse than anticipated when the investor originally invested in the investee;

• adverse regulatory action is expected to substantially reduce the investee’s product demand or profitability;

• the investee has lost significant customers or suppliers with no immediate prospects for replacement;

• the investee’s discounted or undiscounted cash flows are below the investor’s carrying amount; and

• the investee’s industry is declining and significantly lags the performance of the economy as a whole.

The determination of fair value of the Company's investment in the LLC is a significant estimate.  Management has conducted quarterly evaluations of its investment in the LLC, with the assistance of a valuation specialist as needed, to determine the fair value utilizing an income approach and probability scenarios of discounted cash flows.  In conducting these evaluations, management made a variety of assumptions that it believes to be reasonable.  Variations in many of these assumptions could have a significant impact on the calculation of the fair value and the resulting level of impairment recorded.  Furthermore, these assumptions are based on the facts and circumstances at the date of the evaluations and are subject to change.  See the Equity Investment in Mountain Valley Pipeline section for additional information regarding the LLC valuation.

Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of ASC 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 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 established a reserve for rate refund related for the difference in the settlement rates approved by the SCC staff and the interim rates implemented effective January 1, 2023.  Once a final order is issued by the SCC, the Company will refund the excess billings to its customers.

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The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or payable. At the end of each WNA year, the Company refunds excess revenue collected for weather that was colder than the 30-year average or bills customers for revenue short-fall resulting from weather that was warmer than normal.  In a manner similar to the SAVE Rider, the Company also has an SCC approved mechanism to recover the investment and expenses for the operation of the RNG facility.  As required under the provisions of ASC 980, the Company recognizes billed revenue related to SAVE projects, RNG and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,240,097 and $1,585,062 as of September 30, 2023 and 2022, respectively.

Under the provisions of ASU 2014-09, Revenue from Contracts with Customers, the Company recognizes revenues when natural gas is delivered to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through both billed and unbilled customer usage. The Company also recognizes revenue through ARPs, including the WNA.

Allowance for Credit Losses - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The historical model used in valuing reserve for bad debts has been consistently applied prior to COVID-19 and has produced reasonable estimates for valuing the potential credit losses on customer accounts receivable. With the arrival of COVID-19 and the unprecedented widespread impact deriving from the pandemic, including the 17-month disconnection moratorium which ended August 30, 2021, the estimation of the Company's allowance for credit losses was more subjective with greater reliance on qualitative assessments and judgment rather than historical patterns.  This greater focus on qualitative assessments continued into fiscal 2022 as the residual impact of COVID and the availability of federal financial assistance through the CARES Act and ARPA that were incorporated into fiscal 2021 credit loss estimates continued to have an effect on customer payment patterns.  In fiscal 2023, customer account activity returned to pre-COVID levels where customer payment patterns and account aging were more predictable and prior valuation techniques were again applicable.  Based on management's evaluation and assessments, the total allowance for credit losses were estimated at $155,164 and $371,271 as of September 30, 2023 and 2022, respectively.

Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 9 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporates the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 5.63% for valuing both its pension plan and postretirement plan liabilities at September 30, 2023. These discount rates represent an increase from the 5.15% for the pension plan and 5.16% for the postretirement plan used for valuing the corresponding liabilities at September 30, 2022. The increase in discount rates corresponds to the market reactions to the continuing inflationary pressures on the financial markets and economy.  The yield on the 30-year Treasury increased from 2.08% at September 30, 2021 to 3.79% at September 30, 2022 and to 4.73% at September 30, 2023. Corporate bond rates experienced a smaller increase as credit spreads have narrowed. The rise in the discount rates was the primary factor in the reduction of the benefit obligations for both the pension and the postretirement plan. Mortality assumptions were based on the PRI-2012 Mortality Table with improvements projected generational using Projection Scale MP-2021 for the current year valuation.

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Management has focused on reducing risk in the Company's defined benefit plans through different means including offering lump sum payouts to vested terminated participants and implementing a "soft freeze" on the plans.  In 2017, the Company implemented a soft freeze to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This soft freeze mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement plan.  Each of these strategies have served to limit liability growth and reduce volatility.

The Company also has focused on its asset investment strategy. With the soft freeze of both the pension and postretirement plans, future liability growth associated with participant service and compensation has been limited.  Under the pension plan, the portion of the liability attributable to active eligible employees continuing to accrue benefits has declined from 56% of the liability as of the date of the soft freeze to 38% in fiscal 2023.  The remaining 62% of the 2023 liability is set, subject to variability in the discount rate and mortality adjustments.  Since January 2017, when the pension plan froze access to new employees, the asset allocation has transitioned from 60% equity and 40% fixed income to 25% equity and 75% fixed.  During the same period, the fixed income portion of the plan was transitioned to an LDI approach, with the fixed income assets invested in securities with a duration that corresponds to the duration of the corresponding liability.  This synchronization of the pension assets with the pension liabilities has reduced volatility in the funded status of the plan.  This is evidenced by the relative stability of the funded status of the pension plan at September 30, 2023 and 2022 with a funded ratio of 100% and 103%, respectively.  The 25% allocation to equity investments provides asset growth potential to offset increases in the pension liability related to those employees continuing to accrue benefits. Management will continue to evaluate the investment allocation as the liabilities mature and make adjustments as necessary.

The Company has initiated a transition of the postretirement plan assets from a 50% equity and 50% fixed income allocation to a 30% equity and 70% fixed income allocation.  This revision to the investment targets is in response to a greater proportion of participants that have transitioned to retirement.  As the postretirement plan implemented the soft freeze in 2000, only 25% of the plan's liability is currently attributable to active employees with the remaining liability associated with retired participants. Similar to the pension plan, the revision to the asset allocation will seek to reduce the volatility in funded status while still providing the opportunity for asset growth through the equity portion of the portfolio.  The funded status for the postretirement plan was 116% and 98% as of September 30, 2023 and 2022, respectively.  The improvement in the funded status was due to the higher equity allocation and shorter duration of the fixed income portion of the portfolio compared to the duration of the corresponding plan liabilities.  Management will continue to monitor and evaluate the asset allocation and adjust as warranted.

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

The Company annually evaluates the long-term rate of return on its targeted investment allocation model, as well as the overall asset allocation of its benefit plans, and reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions.  Management maintained the long-term rate of return assumption at 4.50% for fiscal 2023 based on evaluation by the Company's investment advisor and management's assessment of the current market environment. The long-term rate of return for the postretirement plan increased slightly from 3.95% in fiscal 2023 to 4.24% for fiscal 2024. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

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Management estimates that the Company will have no minimum funding requirements next year.  The Company currently does not expect to make contributions to its pension plan and postretirement plan in fiscal 2024 due to other financing considerations and the funded position of the plans. 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.

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.

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of ASC 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 five interest-rate swaps outstanding at September 30, 2023 related to its variable rate notes. See Notes 1 and 7 to the consolidated financial statements for additional information regarding the swaps.

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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. As a wholly-owned subsidiary of Resources, Midstream is a more than 1% investor in the MVP and a less than 1% investor in Southgate. More information regarding the investment in MVP is provided below and under the Equity Investment in Mountain Valley Pipeline section.

Primarily due to decisions in January and February 2022 by the Fourth Circuit vacating and remanding certain permits necessary for the completion of MVP construction and its commercial operation, and the greater uncertainty that exists given the Fourth Circuit's more recent hearing involving an MVP permit, as well as the consequent actions by project partners to impair their respective investments and revocation of the previously disclosed summer 2022 in-service target date, Midstream determined that in April 2022 its investment in the LLC experienced an other-than-temporary decline in value.  Accordingly, management recorded a $39.8 million impairment to the value of its investments in the second quarter of fiscal 2022.  In November 2022, Resources re-assessed the valuation of its investment in MVP in response to the Fourth Circuit's comments regarding a challenge to a water permit certification from the West Virginia Department of Environmental Protection, ongoing delays in the permitting process as well as the additional impairment recognized by the LLC's managing partner.  As a result, management recorded an additional $15.3 million impairment in the fourth fiscal quarter of 2022 to reflect an additional other-than-temporary decline in value.  In determining the current valuation, the Company, with the assistance of a third party valuation specialist, conducted an evaluation of Midstream's investment to incorporate the recent legal and governmental responses and the expected impact to future cash flows.  As of September 30, 2022, the impairment of the investment in the LLC totaled $55.1 million.

The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions and rates charged to customers for natural gas service, safety standards, extension of service and depreciation. Nearly all of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates authorized by the SCC. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.  These rates are determined based on the filing of a formal non-gas rate application with the SCC.  Generally, investments related to extending service to new customers are recovered through the additional revenues generated by the non-gas base rates in place at that time.  The investment in replacing and upgrading existing infrastructure, as well as recovering increases in non-gas expenses due to inflationary pressures, regulatory requirements or operation needs are generally not recoverable until a formal rate application is filed to include additional investment and higher costs, and new non-gas base rates are approved.  The gas portion of rates are adjusted at least quarterly by administrative approval based on filings submitted by the Company.

The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERC regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.

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

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The SAVE Rider provides the Company with a mechanism through which it recovers costs related to SAVE qualified infrastructure investments on a prospective basis, until a formal rate application is filed to incorporate these investments in non-gas base rates.  The SAVE Plan and Rider were last reset effective January 1, 2019, when the recovery of all prior SAVE Plan investment was incorporated into the current non-gas rates.  Accordingly, SAVE Plan revenues continue to increase year over year with fiscal 2022 levels reaching $3,286,000 compared to $2,487,000 in fiscal 2021, reflecting the Company's cumulative investment in qualified SAVE Plan infrastructure since 2019. The current SAVE Plan is focused on replacing first generation, pre-1973 plastic pipe and other qualifying infrastructures projects. Additional information regarding the SAVE Plan and Rider is provided under the Regulatory section below.

The WNA mechanism 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 a level of 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 to its customers 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 and thereby estimates the revenue adjustment based on weather variance from normal.  Any billings or refunds related to the WNA are completed following each WNA year, which extends for the 12-month period from April to March. The Company recorded approximately $1,973,000 and $1,196,000 in additional revenue from the WNA for weather that was approximately 13% and 8% warmer than normal for the fiscal years ended September 30, 2022 and 2021, respectively.  The number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal years to replace historical colder years, the number of heating degree days that defines normal has trended downward over the last several years.

The Company also has an approved rate structure in place that mitigates the impact of financing costs of its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue by applying the ICC factor, based on the Company’s weighted-average cost of capital, including interest rates on short-term and long-term debt, and the Company’s authorized return on equity, to the average cost of natural gas inventory during the period.  Total ICC revenues increased from $396,000 in fiscal 2021 to $657,000 in fiscal 2022 in response to the impact of rising natural gas commodity prices on average natural gas storage balances.  Monthly average inventory balances, used to calculate ICC revenues, increased by 69% and ending storage balances increased by 115% year over year.

The cost of natural gas is a pass-through cost and is independent of the non-gas rates of the Company. Accordingly, the Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs based on a quarterly filing, or more frequent if necessary, with the SCC. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Roanoke Gas is required to submit an AIF each year to the SCC. Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets. If the results of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery is accelerated to the point where the actual return for the period adjusts to the mid-point of the range.  In years when Roanoke Gas files an application for an increase in non-gas base rates, an AIF is not required; however an earnings test must be completed as part of the application filing. As a result of the preliminary earnings tests conducted in 2022 and 2021, Roanoke Gas expensed $232,000 in regulatory assets related to the R&D tax credit study, a portion of which were incurred during fiscal 2022, and $57,000 in deferred COVID costs in September 2022; and in September 2021, Roanoke gas expensed $217,000 in deferred COVID costs incurred during that period.

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COVID-19

As was discussed under Item 1A "Risk Factors" above, COVID-19 and the resulting pandemic continues to impact the local, state, national and global economies. Supply chain disruptions, labor shortages and inflation have supplanted quarantines and government restrictions as the primary examples of matters impacting economic conditions.  Significant progress was made in distributing and administering vaccines to the public through September 30, 2022, which has allowed a return to mostly normal operating conditions. Most restrictions implemented as a result of the pandemic have been eased, including Virginia’s state of emergency, allowing for increased business, recreational and travel activities. Natural gas consumption by the Company’s commercial customers has largely returned to pre-pandemic levels. However, the easing of restrictions and the existence of variant strains of COVID-19 may lead to a rise in infections, which could result in the reinstatement of some or all of the restrictions previously in place. Management continues to monitor current conditions to ensure the continuation of safe and reliable service to customers and to maintain the safety of the Company's employees.

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

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

Cyber Risk

Cyber attacks are a constant threat to businesses and individuals. The Company remains focused on these threats and is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important operational and financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management continuously monitors access to these systems and believes it has security measures in place to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial costs that may result from a cyber incident.

Inflation and Rising Prices

Natural gas commodity, delivery and storage capacity costs constitute the single largest expense of the Company representing 61% of fiscal 2022 total operating expenses.  Natural gas commodity prices have increased through fiscal 2022 with a sharp rise during the fiscal third and fourth quarters.  Several factors have contributed to rising natural gas prices including lack of interstate pipeline development, demand rebounding as activity returns to pre-pandemic levels, lower inventory storage levels, increased demand for cleaner energy and global energy conditions, including the Russia/Ukraine conflict.  Roanoke Gas can recover rising natural gas costs through the PGA mechanism as noted above; however, in times of rapidly increasing costs, the timing of recovery may lag.  Increasing natural gas prices, especially in relation to other energy options, may lead to reductions in energy consumption through customer conservation or fuel switching in addition to the potential for higher bad debts related to customers inability to pay higher natural gas bills.

Inflation, due to supply chain delays, labor shortages and limited availability of critical supplies among other factors, affects the Company through increases in non-gas expenses such as labor, employee benefits, materials and supplies, contracted services, corporate insurance and other areas.  The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas rate application results in an inherent lag in non-gas expense recovery.  Therefore, authorized non-gas rates may not keep pace with the rising costs during inflationary periods.  Management regularly evaluates the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas rate adjustment. Accordingly, management plans to file a non-gas rate application in early December 2022 to incorporate the increased expense levels and additional rate base, including both SAVE and Non SAVE related plant, since the last non-gas base rate application.  See the Regulatory section for more information.

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Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which is primarily associated with the utility segment. Additional segment analysis is provided in areas where Midstream's investment in affiliates represents a significant component of the comparison.  Net income decreased by $41,834,664 to a net loss of $31,732,602 for the year ended September 30, 2022 primarily due to the impairment of the LLC investment and lower equity in earnings.

The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated income statement under the line item cost of gas - utility. The cost of natural gas, 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, is passed through to customers at the Company's cost.  Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. The following results of operations analyses will reference gross utility margin.

Fiscal Year 2022 Compared with Fiscal Year 2021

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

Total gas utility operating revenues for the year ended September 30, 2022 increased by 12% from the year ended September 30, 2021 primarily due to higher natural gas commodity prices, increases in SAVE and ICC revenues and higher transportation and interruptible volumes.  Rising natural gas commodity prices resulted in a 40% per DTH increase in the commodity component of revenue and a 16% per DTH increase in total revenue.  The total demand component of revenue remained relatively unchanged as the corresponding transportation and storage fees declined slightly from the prior year.  Corresponding to the increase in natural gas commodity prices, ICC revenues rose 66% as the average storage injection price per DTH increased from $3.19 last year to $7.98 for the current year.  Transportation and interruptible volumes, primarily driven by business activity rather than weather, increased by 20% due to a single multi-fuel customer that switched its primary fuel to natural gas from an alternate energy source.  Over the last few years, this customer has alternated its primary energy source between natural gas and alternative fuels.  Accordingly, Roanoke Gas expects volatility in the this customer's usage patterns to continue.  Excluding the multi-fuel customer's usage from both periods, total transportation and interruptible volumes would have increased by approximately 2% on a comparative basis.  The weather sensitive residential and commercial natural gas deliveries decreased by 3% corresponding to the decline in heating degree days.

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Gross utility margin increased over the prior fiscal year primarily as a result of the aforementioned higher SAVE and ICC revenues, increase in transportation and interruptible deliveries and higher WNA adjusted residential and commercial margins. Even though residential and commercial volumes decreased by 3%, after adjusting for the impact of warmer weather, the WNA mechanism provided for additional margins equivalent to nearly 100,000 DTH more than the corresponding WNA adjusted margin for the prior year.  Other revenues increased due to reinstatement of late payment fees and charges that were suspended during the moratorium prohibiting the disconnection of customers for late or non-payment.  When the moratorium was lifted on August 30, 2021, the Company resumed the assessment of these fees.

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

Operations and Maintenance Expense - Operations and maintenance expense increased by $1,012,885, or 7%, over the prior year primarily due to increases in bad debt expense, corporate insurance premiums, professional and contracted services and the accelerated amortization of certain regulatory assets, net of higher capitalized overheads.  Bad debt expense increased by $900,000 as the prior year included more than $400,000 in CARES Act funds and $859,000 in ARPA funds applied to delinquent customer account balances.  Bad debt expense was also impacted in the current fiscal year due to higher customer bills related to rising natural gas commodity prices and delinquencies attributed to the prior year moratorium that prevented service disconnections for non-payment until after August 30, 2021.  Corporate insurance premiums increased by $194,000 due to insurance market conditions.  Contracted services increased by $225,000 due to facility maintenance projects, higher costs for the customer call center and cyber security enhancements.  Roanoke gas expensed an additional $289,000 in deferred regulatory assets related to COVID and the R&D tax credit study, compared to $217,000 in the prior year related to COVID expenses as a result of the earnings test conducted for each of the respective years.  The accelerated expensing of deferred costs was required as Roanoke Gas' actual returns exceeded the top of the authorized return range as defined in the last non-gas rate award.  Total capitalized overheads increased by $391,000 on a $5.5 million increase in capital expenditures primarily related to the RNG and capital project timing.

General Taxes - General taxes decreased by $4,893, or less than 1%.   Property tax expense was nearly unchanged as a 7% increase in gross utility property was offset by a corresponding reduction in the assessed values reported by the SCC to the Company.

Depreciation - Depreciation expense increased by $524,303, or 6%, corresponding to a similar increase in depreciable utility property.

Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment decreased by $1,594,227 as the limited growth construction activities and the related accrual of AFUDC ceased in October 2021.  The prior fiscal year reflected higher activity levels early in the year, followed by a halt in growth activities and AFUDC during the second fiscal quarter with limited construction resuming in April 2021 and a much lower level of AFUDC recognized for the remainder of fiscal 2021.  See the Equity Investment in Mountain Valley Pipeline section for additional information.

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Impairment of Unconsolidated Affiliates - The $55,092,303 impairment is due to two other-than-temporary write-downs of the Company's investment in the LLC that were made during the second and fourth quarters of fiscal 2022.  See Equity Investment in Mountain Valley Pipeline and Critical Accounting Policies and Estimates sections for more information.

Other Income, net - Other income increased by $544,837, or 60%, primarily due to a $345,000 decrease in the non-service cost components of net periodic benefit costs and $219,000 in income related to gas distribution property donated by a local housing authority. After receiving approval from the SCC, Roanoke Gas acquired the natural gas facilities from two apartment complexes in exchange for assuming the responsibility for the operation and maintenance of these assets.  The fair value of these assets were reflected in utility property with an offsetting credit to income. See the Regulatory section for more information.

Interest Expense - Total interest expense increased by $446,044, or 11%, due to a combination of higher total debt levels and increasing interest rates on the Company's variable rate debt.  Total average debt outstanding increased by 8% to meet the funding needs of Roanoke Gas' capital projects and Midstream's continuing investment in the LLC.  The average interest rate increased by 10 basis points as the higher rates on the Company's variable rate debt offset lower rates on the Company's new fixed rate debt issuances.  Total borrowing levels were mitigated by the infusion of $22 million of the $27 million proceeds from the March equity offering into Roanoke Gas and Midstream.

Roanoke Gas' interest expense increased by $189,819, or 7%, as total average debt outstanding increased by $7,300,000 associated with two new debt issues totaling $25,000,000, of which the proceeds were used to pay down the capital bridge financing provided by the line-of-credit and contribute additional financing for the capital budget.  The average interest rate decreased slightly from 3.48% in fiscal 2021 to 3.38% in fiscal 2022. The lower average interest rate was attributable to the two new debt issues that have interest rate swap rates of 2.00% and 2.49%, respectively.

Midstream's interest expense increased by $256,225, or 21%, as the average interest rate on Midstream's total debt increased from 2.23% to 2.59% related to rising interest rates on the variable rate credit facility combined with a $2,600,000 increase in total average debt outstanding during the period.

Income Taxes - Income tax expense decreased by $14,614,707, moving from a tax expense of $3,204,062 in fiscal 2021 to a net tax benefit of $11,410,645 due to a net deferred tax benefit of $14,180,759 in fiscal 2022 corresponding to the recognition of the impairment of the Company's investment in the LLC. The effective tax rate was 26.5% for fiscal 2022 compared to 24.1% for fiscal 2021. The effective tax rate for the current fiscal year exceeded the combined federal and state statutory rate of 25.74% due to the combination of moving to a taxable loss position combined with additional deductions related to the amortization of the R&D tax credits. Excluding the impairment, the effective tax rate for fiscal 2022 would have been 23.2% representing a decline from 24.1% in the prior year.

Earnings Per Share and Dividends - Basic and diluted loss per share were $3.48 in fiscal 2022 compared to $1.22 earnings per share in fiscal 2021. Dividends declared per share of common stock were $0.78 in fiscal 2022 compared to $0.74 in fiscal 2021.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the impact of weather variability, the Company’s primary capital needs are the funding of its capital projects, investment in the LLC, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends to shareholders.  The Company anticipates funding these items through its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock.

Cash and cash equivalents increased by approximately $3.4 million in fiscal 2022 compared to $1.2 million in fiscal 2021. The following table summarizes the categories of sources and uses of cash:

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Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year, as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash flows from operating activities increased by nearly $4 million from the prior year. The table below summarizes the significant components operating cash flow:

Recovery of the prior year under-collection of gas costs and receipt of supplier refunds, net of the impact of the continuing rise in natural gas commodity prices, accounted for much of the nearly $4 million increase in operating cash flows.  At September 30, 2021, Roanoke Gas was in a net under-collected gas cost position of more than $5 million due to timing in adjusting the PGA factor for rising gas costs.  During fiscal 2022, Roanoke Gas collected, through customer billings, nearly $3.6 million of the prior year under-collection.  Roanoke Gas also received supplier refunds totaling nearly $2.7 million from the pipelines that serve the Company.  These refunds are required to be returned to customers over a 12 month period, which began in July 2022.  As noted above, natural gas prices have risen steadily over the last two years; however, commodity prices took a sharp increase during the summer of fiscal 2022, which resulted in an increase in gas in storage of more than $9 million over the same period last year.  The prior fiscal year also reflected an increase of $2.1 million as natural gas prices increased at a slower pace.  As a result, the change in under-collection of gas costs and the receipt of the supplier refunds provided $7.0 million and $2.5 million in additional operating cash flow over last year, while the much higher cost of gas in storage resulted in a reduction of $6.9 million in operating cash flow from last year.  The impairments on the Company's investment in the LLC resulted in significant swings in net income, deferred taxes and the recognition of impairment charges; however, they did not have an operating cash flow impact.

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Other significant fluctuations in cash flows from operations include $2.4 million in the prior year primarily related to the establishment of a regulatory liability for the R&D tax credits and the corresponding $2.9 million increase in prepaid income taxes primarily attributable to the pending refunds for the R&D tax credits.

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility property, 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 Midstream's continued investment in the LLC.  Roanoke Gas' expenditures were approximately $25.5 million and $20.0 million in fiscal 2022 and 2021, respectively. Roanoke Gas renewed 8.3 miles of main and 605 service lines and 7.8 miles of main and 620 service lines in fiscal years 2022 and 2021, respectively. The current SAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe in addition to other SAVE related infrastructure. Furthermore, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to 544 customers in fiscal 2022, compared to 480 customers in fiscal 2021. Depreciation covered approximately 36% and 43% of the current and prior year's capital expenditures, respectively, with the balance provided from other operating cash flows and financing activities.

Capital expenditures are expected to be around $20 million annually over the next few years as Roanoke Gas continues to focus on its SAVE Plan, completion of the RNG project, as well as system improvements and customer growth. The Company expects to utilize its credit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the fiscal 2022 funding of $5.3 million for Midstream's participation in the LLC. Based on the LLC's managing partner's most recent projections, Midstream's total expected funding requirement is expected to increase to between $68 and $70 million as discussed below, with anticipated cash investment to be approximately $13 million over the next 12 to 24 months. Funding for the investment in the LLC is provided through Midstream's credit facility and three unsecured notes in the combined amount of $32 million. More information regarding the credit facility is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $18.4 million and $15.5 million in fiscal 2022 and 2021, respectively.  The increase in financing cash flows was primarily attributable to Resources' $27 million equity offering in March 2022 of which $12 million was invested in Roanoke Gas and $10 million in Midstream.  Due to these cash infusions from the equity issue and the issuance of Roanoke Gas' $15 million and $10 million unsecured notes and Midstreams' $8 million note, Roanoke Gas was able to pay down its line-of-credit balance and maturing $7 million note and Midstream applied $18 million against its non-revolving credit facility and $125,000 related to an amortizing note.  The Company also realized another $2.0 million from the issuance of stock through DRIP activity, the ATM program and the exercise of options. Cash out-flows for dividend payments exceeded $7.0 million as the annualized dividend rate increased from $0.74 to $0.78 per share and total outstanding shares increased significantly as a result of the equity offering. The Company’s consolidated capitalization was 40.4% equity and 59.6% long-term debt at September 30, 2022, exclusive of unamortized debt expense. This compares to 41.5% equity and 58.5% long-term debt at September 30, 2021.

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Based on the LLC's projected cash requirements for MVP, which includes MVP construction resuming in 2023, Midstream will need between $15 million and $17 million in additional capital over the next 12 to 24 months to meet its funding commitments to the LLC and cover Midstream's operating and financing expenses.  Additionally, the $21.9 million credit facility is scheduled to mature on December 31, 2023 as well as  debt service related to monthly and quarterly scheduled installment payments on two of Midstream's unsecured notes in fiscal 2023 and 2024. Various options are being evaluated, including seeking additional borrowing capacity from its lending partners and/or equity infusion from Resources.

As of September 30, 2022, Roanoke Gas had $28 million available under its line-of-credit agreement. In addition, Roanoke Gas also has private shelf agreements with two different financial institutions.  The first agreement provides for the issuance of up to $40 million in unsecured notes in addition to the $28 million previously issued.  This shelf agreement is scheduled to expire on December 6, 2022; however, management expects to reach an agreement to extend the term of the agreement.  The second agreement provides for the issuance of up to $70 million in unsecured notes during its current term, which expires September 30, 2025.  These debt facilities along with potential equity issuances should provide the Company with sufficient funding to meet its liquidity needs over the next 12 months.

Notes 6 and 7 provide details on the Company's line-of-credit and three debt issuances mentioned above.

ATM Program

Resources issued 4,872 shares of common stock for $112,500, net of $2,813 in fees, under the ATM program for the year ended September 30, 2022.  For the year ended September 30, 2021, Resources issued 142,726 shares of common stock for $3,400,443, net of $85,221 in fees, under the ATM program.

Off-Balance Sheet Arrangements

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

Equity Investment in Mountain Valley Pipeline

Recent construction activity has been limited based on legal and regulatory challenges. Although certain permits and authorizations were received, the MVP project has been subject to repeated, significant delays and cost increases because of legal and regulatory setbacks, particularly in respect of litigation in the Fourth Circuit in January and February 2022 as discussed below.

Following a comprehensive review of all outstanding stream and wetland crossings across the approximately 300-mile MVP project route, on February 19, 2021, the LLC submitted (i) a joint application package to each of the Huntington, Pittsburgh and Norfolk Districts of the U.S. Army Corps of Engineers (Army Corps) that requests an individual permit from the Army Corps to cross certain streams and wetlands utilizing open cut techniques (the Army Corps Individual Permit) and (ii) an application to amend the MVP project’s CPCN that seeks FERC authority to cross certain streams and wetlands utilizing alternative trenchless construction methods.  On April 8, 2022, the FERC authorized the amended CPCN.

Related to seeking the Army Corps Individual Permit, on March 4, 2021, the LLC submitted applications to each of the West Virginia Department of Environmental Protection (WVDEP) and the Virginia Department of Environmental Quality (VADEQ) seeking Section 401 water quality certification approvals or waivers (such approvals or waivers, the State 401 Approvals).  The State 401 Approvals were both issued in December 2021 and are the subject of ongoing litigation.

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On January 25, 2022, the LLC’s authorizations related to the Jefferson National Forest (JNF) received from the Bureau of Land Management and the U.S. Forest Service were vacated and remanded on specific issues by the Fourth Circuit. On February 3, 2022, the Fourth Circuit vacated and remanded on specific issues the Biological Opinion and Incidental Take Statement issued by the United States Department of the Interior’s Fish and Wildlife Service for MVP.  On May 3, 2022, the operator for MVP announced that after evaluating legal options and consulting with the relevant federal agencies, the LLC planned to pursue new authorizations relating to the JNF and a new Biological Opinion and Incidental Take Statement.  Related to pursuing a new Biological Opinion and Incidental Take Statement, on July 29, 2022, the LLC submitted to the U.S. Fish and Wildlife Service an updated supplement to the Biological Assessment (and notified the FERC of such submission), which updated supplement is intended to address aspects of the Fourth Circuit's February 2022 ruling and points raised by project opponents.

Given ongoing litigation and regulatory matters, on June 24, 2022, the LLC filed a request with the FERC for an extension of time to complete the project for an additional four years (relative to a prior obtained extension) through October 13, 2026, which request was granted on August 23, 2022.

On October 25, 2022, oral argument was held in the Fourth Circuit relating to the WVDEP State 401 approval, which oral argument was conducted by the same panel of Fourth Circuit judges as have appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP. Based upon the oral argument, the project operator perceives continued hostility to and risk posed by the Fourth Circuit panel to the LLC’s State 401 Approvals and those potential future authorizations and permits within the Fourth Circuit’s jurisdiction, including any new authorizations for the JNF and new Biological Opinion and Incidental Take Statement. Further, as of the filing of this Annual Report on Form 10-K, there remains uncertainty with respect to the relevant federal agencies' final permitting issuance timelines.

Notwithstanding prior setbacks and ongoing risks, the MVP Joint Venture continues to engage in pursuing the requisite authorizations necessary under applicable law from the relevant agencies to complete the MVP project. However, in light of the continuing and likely future litigation and regulatory challenges posed to the MVP project (including the need for existing or future authorizations to remain in effect notwithstanding any pending or future challenge thereto) and timing uncertainties within the permitting process, the Company believes that the best path to complete the MVP in accordance with the Company’s previously-communicated targeted full in-service date for the project during the second half of 2023 and at a targeted total project cost of approximately $6.6 billion (excluding AFUDC) is for the United States Congress to expeditiously pass, and there to be enacted, federal energy infrastructure permitting reform legislation that specifically requires the completion of the MVP project, similar to MVP-specific aspects of legislation proposed in September 2022 by each of United States Senators Joseph Manchin and Shelley Moore Capito.

As noted above, the LLC has sought new authorizations relating to the JNF, a new Biological Opinion and Incidental Take Statement, and the Army Corps Individual Permit. In order to complete the project, in addition to the authorizations with respect to water crossings and other relevant regulatory matters, the LLC needs to continue to have available the orders previously issued by the FERC that are necessary to complete the MVP project and receive authorization from the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order and in the JNF. The LLC also is participating in the defense of the State 401 Approvals, which are the subject of ongoing litigation in the Fourth Circuit.

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

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In April 2018, the LLC announced the Southgate project and submitted Southgate's certificate application to the FERC in November 2018.  In June 2020, the FERC issued the CPCN for Southgate; however, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for MVP and the Director of the Office of Energy Projects lifts the stop work order and authorizes the LLC to continue constructing MVP.  In addition, there have been certain other litigation and regulatory-related delays affecting completion of the MVP Southgate project, including on August 11, 2020, the North Carolina Department of Environmental Quality denied Southgate's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding MVP's completion, which denial was reissued in April 2021 following an appellate proceeding.  On December 3, 2021, the Virginia State Air Pollution Control Board denied the permit for Southgate's Lambert compressor station, which decision the LLC initially appealed before withdrawing its request to review the denial.

Given the continually evolving regulatory and legal environment for greenfield pipeline construction projects, as well as factors specific to MVP and Southgate, the LLC continues to evaluate Southgate including engaging in discussions with Dominion Energy North Carolina regarding options with respect to Southgate, including likely refining the project's design, scope and timing.  Dominion Energy North Carolina's obligations under the precedent agreement in support of the original project are subject to certain conditions, including that the LLC would have completed construction of the project facilities by June 1, 2022, which deadline is subject to extension by virtue of previously declared events of force majeure.  The project operator has announced that it is unable to predict the results of the discussions between the LLC and Dominion Energy North Carolina, including any potential modifications to the project, or ultimate undertaking or completion of the project.

Management conducted an assessment of its investment in the LLC in accordance with the provisions of ASC 323, Investments - Equity Method and Joint Ventures. This assessment included a third-party valuation.  As a result of its evaluation, management concluded that the investment in the LLC sustained an other-than-temporary decline in fair value as of February 22, 2022 and recorded a pre-tax impairment loss of approximately $39.8 million in its second quarter operating results to the consolidated financial statements. Management re-evaluated its investment as of September 30, 2022 and recognized an additional $15.3 million impairment in the fourth quarter.  Management will continue monitoring the status of MVP and Southgate for circumstances that may lead to future impairments, including further delays or denials of necessary permits and approvals. If necessary, the amount and timing of any further impairment would be dependent on the specific circumstances, including changes to probabilities of completion, and changes in the assumed future cash flows, and discount rate at the time of evaluation.

Midstream had borrowing capacity of $23 million under its non-revolving credit facility, which matures in December 2023. As of September 30, 2022, $21.9 million had been utilized.  Effective November 1, 2021, the borrowing capacity under this credit facility was reduced to $33 million as $8 million of the outstanding balance was re-financed through a separate unsecured promissory note.  Effective March 31, 2022, the borrowing capacity under the credit facility was further reduced to its current $23 million level as $10 million of the outstanding balance was paid.  See Note 7 for more information. This credit facility will provide limited financing capacity for MVP funding; however, due to ongoing delays, additional financing will be required. Management is evaluating various options to secure the necessary capital including discussions with Midstream's current lenders and the potential for additional equity capital. If the legal and regulatory challenges, including any future challenges, are not resolved in a timely manner and/or restrictions are imposed that impact future construction, the cost of the MVP and Midstream's capital contributions may increase above current projections.

Regulatory

In April 2020, the SCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date. Roanoke Gas deferred certain COVID-19 related costs during fiscal 2022 and 2021.  However, based on the Company’s preliminary earnings test for those years, Roanoke Gas' earnings exceeded the authorized return on equity on which the Company’s rates were established in its last rate proceeding.  Accordingly, Roanoke Gas expensed $57,000 and $217,000 in COVID-19 related deferred costs during the fourth quarter of fiscal 2022 and 2021, respectively.

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Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Rider.  In May 2022, Roanoke Gas filed its most recent SAVE application with the SCC to update the SAVE Plan and Rider for the period October 2022 through September 2023.  The updated SAVE Rider is designed to collect approximately $4.1 million in annual revenues representing approximately a $650,000 increase over the current SAVE Rider.  The Company received a final order from the SCC on the SAVE Rider application on August 23, 2022 approving the application with the new rates placed into effect in October 2022.

On May 16, 2022, Roanoke Gas announced a cooperative agreement under which Roanoke Gas and the Western Virginia Water Authority will produce commercial quality renewable natural gas, or RNG, from biogas produced at the regional water pollution control plant.  In August 2022, Roanoke Gas filed an application with the SCC seeking approval of a rate adjustment clause under which the Company will recover the costs associated with constructing, owning, operating and maintaining the renewable natural gas facility.  The application was filed under Chapter 30 of Title 56 of the Code of Virginia.  The Company expects a final order from the Commission in January 2023.

On June 2, 2022, Roanoke Gas filed an application with the SCC to acquire certain natural gas distribution assets from a local housing authority.  Under this application, the Company requested the approval to acquire such facilities at five separate apartment complexes, located in the Company’s service territory, that were under housing authority management.  Under the proposed plan, the housing authority would renew existing natural gas distribution facilities to include mains, services and meter installations and then transfer ownership of these facilities to Roanoke Gas.  In turn, Roanoke Gas would assume responsibility for the operation and maintenance of these assets and recognize a gain related to the asset acquisition equal to the cost associated with the renewal.

On July 19, 2022, the SCC approved the application and on August 4, 2022, the housing authority transferred the assets from two apartment complexes to Roanoke Gas. Roanoke Gas recorded these assets and recognized a pre-tax gain of approximately $219,000 during the Company’s fiscal fourth quarter. The housing authority expects to complete the upgrade and subsequent asset transfer at one more apartment complex in fiscal 2023.  The authority is awaiting future funding to complete two additional apartment complexes.  The timing of funding and the completion of the asset renewals for these two complexes is unknown at this time.

On September 30, 2022, the Company filed notice with the SCC that it intended to file a non-gas base rate case.  The Company plans to file in early December with the rates expected to become effective on January 1, 2023 on an interim basis subject to refund.

The final order from the last non-gas base rate increase excluded from current rates a return on the investment in two gate stations that would interconnect with the MVP; however, the SCC allowed Roanoke Gas to defer the related financing costs of those investments for possible future recovery. As a result, the Company began recognizing AFUDC during the second quarter of fiscal 2020 to capitalize both the equity and debt financing costs incurred during the construction phases.  Beginning January 2021, Roanoke Gas temporarily ceased recording AFUDC on its related MVP interconnect construction projects until such time as construction activities resume. For the year ended September 30, 2021, the Company recognized a total of $55,981 in AFUDC related to the two gates stations, $41,978 of equity and $14,003 of debt carrying costs.  In connection with the RNG project, Roanoke Gas began accruing AFUDC in fiscal 2022 associated with construction of the facility.  For the year ended September 30, 2022, Roanoke Gas recognized a total of $75,154 in AFUDC, $59,243 of equity and $15,911 of debt carrying costs.

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

In December 2020, Roanoke Gas received $403,000 in CARES Act funds to assist customers with growing past due balances. Based on guidance provided by the SCC, the Company was able to apply the full amount to eligible customer accounts during the second and third fiscal quarters of fiscal 2021. On October 28, 2021, Roanoke Gas received notification from the SCC that its application for ARPA funds had been approved.  The Company received $859,000 based on arrearage balances as of August 31, 2021.  These funds were considered in the valuation of the estimated allowance for credit losses as of September 30, 2021 and applied to customer accounts in early part of fiscal 2022.

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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.

Investments - Under the provisions of ASC 323, Investments - Equity Method and Joint Ventures, the Company is required to evaluate its investment in the LLC to determine if the fair value of the investments are below the carrying amount and if this decline in fair value is considered other-than-temporary.  If the results of the evaluation indicate that the decline in fair value is other-than-temporary, then the recognition of an impairment is required. The following events or circumstances would indicate the potential of an other-than-temporary decline in the fair value of the investment in the LLC:

• a prolonged period of time that the fair value is below the investor’s carrying value;

• the current expected financial performance is significantly worse than anticipated when the investor originally invested in the investee;

• adverse regulatory action is expected to substantially reduce the investee’s product demand or profitability;

• the investee has lost significant customers or suppliers with no immediate prospects for replacement;

• the investee’s discounted or undiscounted cash flows are below the investor’s carrying amount; and

• the investee’s industry is declining and significantly lags the performance of the economy as a whole.

The determination of fair value of the Company's investment in the LLC is a significant estimate.  Management has conducted quarterly evaluations of its investment in the LLC, with the assistance of a valuation specialist, to determine the fair value utilizing an income approach and probability scenarios of discounted cash flows.  In conducting these evaluations, management made a variety of assumptions that it believes to be reasonable.  Variations in many of these assumptions could have a significant impact on the calculation of the fair value and the resulting level of impairment recorded.  Furthermore, these assumptions are based on the facts and circumstances at the date of the evaluations and are subject to change.  See the Equity Investment in Mountain Valley Pipeline section for additional information regarding the LLC valuation and impairment.

Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of ASC 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the consolidated balance sheet and recorded as expenses in the consolidated statements of income and comprehensive income when such amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future.

If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the consolidated balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred. The write-down of the COVID asset and deferred R&D tax credit study costs are consistent with the provisions of ASC 980.

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

The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or payable. At the end of each WNA year, the Company refunds excess revenue collected for weather that was colder than the 30-year average or bills customers for revenue short-fall resulting from weather that was warmer than normal. As required under the provisions of ASC 980, the Company recognizes billed revenue related to SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,585,062 and $1,191,227 as of September 30, 2022 and 2021, respectively.

Under the provisions of ASU 2014-09, Revenue from Contracts with Customers, the Company recognizes revenues when natural gas is delivered to customers (the performance obligation) based on SCC approved tariff rates (the transaction price). The Company recognizes revenue through both billed and unbilled customer usage. The Company also recognizes revenue through ARPs, including the WNA.

Allowance for Credit Losses - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions. The historical model used in valuing reserve for bad debts has been consistently applied prior to COVID-19 and has produced reasonable estimates for valuing the potential credit losses on customer accounts receivable. With the arrival of COVID-19 and the unprecedented widespread impact deriving from the pandemic, including the 17 month disconnection moratorium which ended August 30, 2021, the estimation of the Company's allowance for credit losses has become more subjective with greater reliance on qualitative assessments and judgment rather than historical patterns.  This greater focus on qualitative assessments continued into fiscal 2022 as the residual impact of COVID and the availability of federal financial assistance through the CARES Act and ARPA that were incorporated into fiscal 2021 credit loss estimates continue to have an effect on customer payment patterns as well as the effect of higher natural gas prices reflected on current customer bills.  Accordingly, based on management's evaluation and assessments, the total allowance for credit losses were estimated at $371,271 and $242,010 as of September 30, 2022 and 2021, respectively.

Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 9 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.

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In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporates the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 5.15% and 5.16%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2022. These discount rates represent an increase from the 2.73% and 2.70% rates used for valuing the corresponding liabilities at September 30, 2021. The increase in discount rates corresponds to the market reactions to the inflationary pressures on the current financial environment resulting from labor shortages and supply chain issues, among other factors.  The yield on the 30-year Treasury increased from 2.08% last year to 3.79% at September 30, 2022. Corporate bond rates experienced a larger increase as credit spreads appear to have widened. The rise in the discount rates was the primary factor in the reduction of the benefit obligations for both the pension and the postretirement plan. Mortality assumptions were based on the PRI-2012 Mortality Table with generational mortality improvements using Projection Scale MP-2021 for the current year valuation.

Management has continued to focus on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested former employees who were not receiving payments under the plan. In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement plan. In October 2020, the Company again offered a one-time lump-sum payout option of deferred pension benefits to those vested terminated employees not currently receiving pension benefits. Lump sum payments of $717,197 were made to those participants that elected this option and reduced corresponding pension liabilities by approximately $965,000 in fiscal 2021.  Each of these strategies have served to limit liability growth and reduce volatility.

The Company also has focused on its asset investment strategy. With the soft freeze of both the pension and postretirement plans, future liability growth associated with participant service and compensation has been limited.  Under the pension plan, the portion of the liability attributable to active eligible employees continuing to accrue benefits has declined from 56% of the liability as of the date of the soft freeze to 39% in fiscal 2022.  The remaining 61% of the 2022 liability is set subject to variability due to changes in the discount rate and mortality adjustments.  Since January 2017 when the pension plan froze access to new employees, the asset allocation has transitioned from a 60% equity and  40% fixed income allocation to a 30% equity and 70% fixed income allocation.  During the same period, the fixed income portion of the plan was transitioned to an LDI approach with the fixed income assets invested in securities with a duration that corresponds to the duration of the corresponding liability for benefits to be paid.  This synchronization of 70% of the pension assets with the pension liabilities has reduced volatility in the funded status of the plan as well as the corresponding expense.  This is evidenced by the September 30, 2022 valuation where the projected benefit obligation declined by $10.4 million primarily due to an actuarial gain of $10.9 million, while total plan assets experienced a decline of $10.9 million, primarily due to rising interest rates reducing the value of the fixed income assets.  Although both components used in determining the funded status reflected significant movements, the funded status still maintained a ratio of 103% for both periods.  The 30% allocation to equity investments provides asset growth potential to offset increases in the pension liability related to those employees continuing to accrue benefits. Management will continue to evaluate the investment allocation as the liabilities mature and make adjustments as necessary.

The Company has not made a change in investment allocation for the postretirement plan assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential.  During fiscal 2022, the postretirement plan assets decreased by $3.7 million and liabilities decreased by $4.4 million.  The funded status for the postretirement plan was 98% and 95% as of September 30, 2022 and 2021, respectively.  As the number of participants in the postretirement plan continue to decline through attrition, management will continue to monitor and evaluate the asset allocation and adjust as warranted.

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

The Company annually evaluates the long-term rate of return on its targeted investment allocation model as well as the overall asset allocation of its benefit plans and reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions.  Management lowered the long-term rate of return assumption from 4.75% in fiscal 2022 to 4.50% in fiscal 2023 based on evaluation by the Company's investment advisor and management's assessment of the current market environment. The long-term rate of return for the postretirement plan declined from 4.25% in fiscal 2022 to 3.95% in fiscal 2023 for the same reasons as the pension plan. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that the Company will have no minimum funding requirements next year. Furthermore, the Company currently does not expect to make contributions to its pension plan and postretirement plan in fiscal 2023 due to other financing considerations. 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.

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.

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of ASC 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 five interest-rate swaps outstanding at September 30, 2022 related to its variable rate notes. See Notes 1 and 7 to the consolidated financial statements for additional information regarding the swaps.

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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

COVID-19

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

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

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

Cyber Risk

Cyber attacks are a constant threat to businesses and individuals. The Company remains focused on these threats and is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important operational financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management continuously monitors access to these systems and believes it has security measures in place to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial costs that may result from a cyber incident.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,600 residential, commercial and industrial customers in Roanoke, Virginia, and the surrounding localities, through its Roanoke Gas subsidiary. Roanoke Gas also provides certain unregulated services. As a wholly-owned subsidiary of Resources, Midstream is a more than 1% investor in the MVP and a less than 1% investor in Southgate. More information regarding the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below.

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The utility operations of Roanoke Gas are regulated by the SCC, which oversees the terms, conditions and rates charged to customers for natural gas service, safety standards, extension of service and depreciation. Nearly all of the Company’s revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas to Roanoke Gas customers based on rates authorized by the SCC. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather.

The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERC regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gas is subject to other regulations which are not necessarily industry specific.

On October 10, 2018, Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates. Roanoke Gas implemented the interim non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019. On January 24, 2020, the SCC issued its final order on the general rate application, granting Roanoke Gas an annualized increase in non-gas base rates of $7.25 million and an authorized rate of return on equity of 9.44%. As a result, the Company refunded $3.8 million to its customers in March 2020, representing the excess revenues collected plus interest for the difference between the final approved rates and the interim rates billed since January 1, 2019. The order also directed the Company to write-off $317,000 of ESAC assets that were not subject to recovery under the final order.

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

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

The WNA model reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on the most recent 30-year temperature average and provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with price protection when the weather is colder than normal. The WNA allows the Company to recover from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal and correspondingly requires the Company to refund the excess margin earned for weather that is colder than normal. Any billings or refunds related to the WNA are completed following each WNA year, which runs from April to March. The Company recorded approximately $1,196,000 and $1,193,000 in additional revenue from the WNA for weather that was approximately 8% warmer than normal for the fiscal years ended September 30, 2021 and 2020.  The number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal years to replace historical colder years, the number of heating degree days that defines normal has declined over the last several years.

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

The cost of natural gas is a pass-through cost and is independent of the non-gas rates of the Company. Accordingly, the Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs based on a quarterly filing, or more frequent if necessary, with the SCC. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Roanoke Gas is required to submit an Annual Information Filing ("AIF") each year to the SCC. Included as part of this filing is an earnings test, which is required when the Company has certain regulatory assets. If the results of the earnings test indicate that the Company's regulatory earnings exceed the mid-point of its authorized return on equity range, then certain regulatory assets are written-down and recovery accelerated to the point where the actual return for the period adjusts to the mid-point of the range. The Company conducted preliminary earnings tests for fiscal 2021 and 2020 in preparation for the AIF filings in January of the subsequent years.  As a result of the preliminary earnings tests, Roanoke Gas expensed $217,000 in deferred COVID costs incurred during fiscal 2021, and fully amortized the remaining $525,000 balance of ESAC assets in fiscal 2020.

Inflation and Rising Prices

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

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

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Results of Operations

The analysis on the results of operations is based on the consolidated operations of the Company, which is primarily associated with the utility segment. Additional segment analysis is provided in areas where Midstream's investment in affiliates represents a significant component of the comparison.

The Company's operating revenues are affected by the cost of natural gas, as reflected in the consolidated income statement under the line item cost of gas - utility. The cost of natural gas is passed through to customers at cost, which includes commodity price, transportation, storage, injection and withdrawal fees with any increase or decrease offset by a correlating change in revenue through the PGA. Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent or replace operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. The following results of operations analyses will reference gross utility margin.

Fiscal Year 2021 Compared with Fiscal Year 2020

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

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

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

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

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

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

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

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

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

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

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

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

Income Taxes - Income tax expense decreased by $101,598, or 3%, on a 4% decrease in pre-tax earnings. The effective tax rate was 24.1% for fiscal 2021 compared to 23.8% for fiscal 2020. The effective tax rate for both years is below the combined state and federal statutory rate of 25.74% due to the amortization of the excess deferred income taxes, the excess deductions related to restricted stock vesting, stock option exercises and the realization of certain tax credits. Income tax expense related to Midstream decreased by $780,000 due to the significant reduction in pre-tax earnings related to AFUDC from the MVP investment. The majority of the remaining $680,000 difference in income tax expense is related to the increase in pre-tax earnings of Roanoke Gas.

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

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its capital projects, investment in MVP, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock.

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

Cash Flows Provided by Operating Activities:

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year, as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, all contribute to working capital levels and related cash flows. Generally, operating cash flows are positive during the second and third fiscal quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth fiscal quarters, operating cash flows generally decrease due to the combination of increasing natural gas storage levels and rising customer receivable balances.

Cash flow from operating activities decreased by nearly $1.3 million from the prior year. The decrease in cash flow provided by operations was primarily driven by the affects of increasing gas commodity prices and changes in certain regulatory assets and liabilities, partially offset by net income exclusive of noncash equity in earnings.

The table below summarizes the significant operating cash flow components:

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

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

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

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures related to investment in Roanoke Gas' utility plant, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and gas distribution system facilities and expansion of its natural gas system to meet the demands of customer growth, as well as the continued investment in the MVP. Roanoke Gas' expenditures were approximately $20 million and $22.9 million in fiscal 2021 and 2020, respectively. Roanoke Gas renewed 7.8 miles of main and 620 service lines and 9.6 miles of main and 592 service lines in fiscal years 2021 and 2020, respectively. The current SAVE Plan is focused on the replacement of pre-1973 first generation plastic pipe in addition to other SAVE related infrastructure. Furthermore, Roanoke Gas’ capital expenditures included costs to extend natural gas distribution mains and services to480 customers in fiscal 2021, compared to 448 customers in fiscal 2020. Depreciation covered approximately 43% and 35% of the current and prior year's capital expenditures, respectively, with the balance provided from other operating cash flows and financing activities.

Capital expenditures are expected to remain at or near current levels over the next three to five years as Roanoke Gas continues to focus on its SAVE Plan, which is expected to be completed by 2024, as well as customer growth and system expansion. The Company expects to utilize its credit facilities, as well as consider additional equity capital, to meet the funding requirements of these planned expenditures.

Investing cash flows also reflect the 2021 funding of $6 million for Midstream's participation in the LLC. Midstream's total expected funding requirement increased to between $60 and $62 million as discussed below, with anticipated cash investment for fiscal 2022 to be approximately $10.7 million. Funding for the investment in the LLC is provided through Midstream's credit facility and two unsecured notes in the combined amount of $24 million. More information regarding the credit facility is provided in Note 7 and under the Equity Investment in Mountain Valley Pipeline section below.

Cash Flows Provided by Financing Activities:

Financing activities generally consist of borrowings and repayments under credit agreements, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $15.5 million and $16.6 million in fiscal 2021 and 2020, respectively. The Company uses its line-of-credit to fund seasonal working capital needs and provide temporary financing for capital projects. The increase in financing cash flows was derived from Midstream's net borrowings of more than $8 million to finance its investment in MVP. The Company also realized $3.3 million from the issuance of common stock through its ATM program and $1.6 million from the issuance of stock through DRIP activity and the exercise of options. Cash out-flows for dividend payments exceeded $6.0 million as the annualized dividend rate increased from $0.70 to $0.74 per share. The Company’s consolidated capitalization was 41.5% equity and 58.5% long-term debt at September 30, 2021, exclusive of unamortized debt expense. This compares to 41.7% equity and 58.3% long-term debt at September 30, 2020.

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

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

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

On March 25, 2021, Roanoke Gas renewed its unsecured line-of-credit agreement for a two-year term expiring March 31, 2023 with a maximum borrowing limit of $40 million. Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits aligned with the Company's seasonal borrowing demand. The Company's total available borrowing limits range from $14 million to $40 million.

On December 6, 2019, Roanoke Gas entered into unsecured notes in the aggregate principal amount of $10 million. These notes have a 10-year term from the date of issue at a fixed interest rate of 3.60%. The proceeds from these notes provided financing for Roanoke Gas' capital budget.

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

On February 14, 2020, Resources filed a prospectus with the SEC utilizing a shelf registration process where the Company may sell shares of common stock, in one or more offerings, of an aggregate amount up to $40 million. The prospectus was filed including a supplement allowing the Company to offer a portion of these shares, up to an aggregate of $15 million, utilizing the ATM approach as defined in Rule 415 under the Securities Act. The ATM Plan allows Resources flexibility in the frequency, timing and amount of share offerings in supplementing its capital funding needs. There were 142,726 shares issued through the ATM program during fiscal 2021.

Off-Balance Sheet Arrangements

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

Equity Investment in Mountain Valley Pipeline

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

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

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

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

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

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

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

Midstream has borrowing capacity of $41 million under its current credit facility, which matures in December 2022. As of September 30, 2021, $33.6 million had been utilized.  Effective November 1, 2021, the borrowing capacity under this credit facility was reduced to $33 million as $8 million of the outstanding balance was termed out in a separate unsecured promissory note.  See the Capital Resources and Liquidity section for more information. This credit facility will provide additional financing capacity for MVP funding; however, due to ongoing delays, additional financing will be required. Management is working with the Company's lending institutions to secure the necessary funding. If the legal and regulatory challenges, including any future challenges, are not resolved in a timely manner and/or restrictions are imposed that impact future construction, the cost of the MVP and Midstream's capital contributions may increase above current projections.

Regulatory

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

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

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

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

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In April 2020, the SCC issued an order allowing regulated utilities in Virginia to defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date. Roanoke Gas deferred certain COVID-19 related costs throughout fiscal 2021.  Based on Roanoke Gas's preliminary earnings test for the period ended September 30, 2021, fiscal 2021 earnings exceeded the mid-point of the authorized return resulting in the COVID-19 related costs being expensed during the fourth quarter.

Roanoke Gas continues to recover the costs of its infrastructure replacement program through its SAVE Rider. In May 2021, the Company filed its most recent SAVE application with the SCC to update the SAVE Plan and Rider for the period October 2021 through September 2022. In its application, Roanoke Gas requested to continue to recover the costs of the replacement of pre-1973 plastic pipe. In addition, the Company requested to include the replacement of certain regulator stations and pre-1971 coated steel pipe as qualifying SAVE projects. The updated SAVE Rider is designed to collect approximately $3.45 million in annual revenues, an increase of approximately $1.1 million from the existing SAVE Rider rates.  The Company received a final order on August 25, 2021 in which the SCC approved the Company’s requested revenue requirement.

Critical Accounting Policies and Estimates

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

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

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

If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the consolidated balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred. The write-downs of the COVID asset and ESAC assets are consistent with the provisions of ASC No 980.

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

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The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As authorized by the SCC, the Company adjusts billed revenues monthly through the application of the WNA model. As the Company's non-gas rates are established based on the 30-year temperature average, monthly fluctuations in temperature from the 30-year average could result in the recognition of more or less revenue than for what the non-gas rates were designed. The WNA authorizes the Company to adjust monthly revenues for the effects of variation in weather from the 30-year average with a corresponding entry to a WNA receivable or payable. At the end of each WNA year, the Company refunds excess revenue collected for weather that was colder than the 30-year average or bills customers for revenue short-fall resulting from weather that was warmer than normal. As required under the provisions of ASC No. 980, the Company recognizes billed revenue related to SAVE projects and from the WNA to the extent such revenues have been earned under the provisions approved by the SCC.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues revenue for estimated natural gas delivered to customers but not yet billed during the accounting period. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The consolidated financial statements include unbilled revenue of $1,191,227 and $1,041,518 as of September 30, 2021 and 2020, respectively.

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

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

The Company is committed to working with its customers during these difficult times by providing extended payment terms and assisting customers in finding other sources of financial aid.  With rising natural gas prices and lingering economic effects from the moratorium and COVID, bad debt concerns will continue into fiscal 2022.

Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 9 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet.

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In selecting the discount rate to be used in determining the benefit liability, the Company utilized the FTSE Pension Discount Curve, which incorporates the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 2.73% and 2.70%, respectively, for valuing its pension plan liability and postretirement plan liability at September 30, 2021. These discount rates represent an increase from the 2.47% and 2.44% rates used for valuing the corresponding liabilities at September 30, 2020. The increase in discount rates corresponds to the inflationary pressures and current market conditions as the economy emerges from the impact of COVID. The yield on the 30-year Treasury increased from 1.46% last year to 2.08% at September 30, 2021. Corporate bond rates experienced a smaller increase as credit spreads appear to have narrowed. The rise in the discount rates was the primary factor in the reduction of the benefit obligations for both the pension and the postretirement plan. Mortality assumptions were based on the PRI-2012 Mortality Table with generational mortality improvements using Projection Scale MP-2020 for the current year valuation.

Management has continued to focus on reducing risk in the Company's defined benefit plans with a greater emphasis on pension plan risk. In 2016, the Company offered a one-time, lump-sum payout of the pension benefit to vested former employees who were not receiving payments under the plan. In 2017, the Company implemented a "soft freeze" to the pension plan whereby employees hired on or after January 1, 2017 would not be eligible to participate. Employees hired prior to that date continue to accrue benefits based on compensation and years of service. This "soft freeze" mirrored the strategy in 2000 when the Company implemented a similar freeze in its postretirement plan. In October 2020, the Company again offered a one-time lump-sum payout option of deferred pension benefits to those vested terminated employees not currently receiving pension benefits. Lump sum payments of $717,197 were made to those participants that elected this option and reduced corresponding pension liabilities by approximately $965,000.  Each of these strategies have served to limit liability growth and reduce volatility.

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

The Company has not made a change in investment allocation for the postretirement plan assets as increasing medical and insurance costs warrant the need for a continued higher allocation to equities for future plan asset growth potential. The postretirement plan assets increased by $2.9 million and liabilities increased by $0.6 million over the last three-year period.  As the number of participants in the postretirement plan continue to decline through attrition, management will continue to monitor and evaluate the asset allocation and adjust as warranted.

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

The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. Understanding the volatility in the markets, the Company reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions. Under the current allocation model for the pension plan, management lowered the long-term rate of return assumption from 5.40% in fiscal 2021 to 4.75% in fiscal 2022 based on the change in the current equity allocation of the pension plan assets and the lower rate of return expected on the fixed income investments. The long-term rate of return was virtually unchanged for the postretirement plan at 4.25% as the asset allocation remains at 50% equity and 50% fixed income. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant.

Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, the Company currently expects to contribute approximately $500,000 to its pension plan and $400,000 to its postretirement plan in fiscal 2022. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums.

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

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.

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s consolidated balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had three interest-rate swaps outstanding at September 30, 2021 related to its three variable rate notes and two interest-rate swaps associated with delayed draw notes to be funded subsequent to fiscal 2021. See Note 7 to the consolidated financial statements for additional information regarding the swaps.

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