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'sstate 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 Regulations section below for more information on the moratorium on disconnection of services, the 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 Gassubsidiary. Roanoke Gasalso 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 Investmentin Mountain Valley Pipeline section below. 17 -------------------------------------------------------------------------------- The utility operations of Roanoke Gasare 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 Gascustomers 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 Transportationin regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. FERCregulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. In addition, Roanoke Gasis subject to other regulations which are not necessarily industry specific. On October 10, 2018, Roanoke Gasfiled a general rate application requesting an annual increase in customer non-gas base rates. Roanoke Gasimplemented 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 Gasan annualized increase in non-gas base rates of $7.25 millionand an authorized rate of return on equity of 9.44%. As a result, the Company refunded $3.8 millionto 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 $317,000of 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 Gashas 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 $2,487,000in fiscal 2021 from $1,272,000in 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 $1,196,000and $1,193,000in additional revenue from the WNA for weather that was approximately 8% warmer than normal for the fiscal years ended September 30, 2021and 2020. The number of heating degree days used to determine normal will change annually as a new year is added to the 30-year period and the oldest year is removed. As a result of adding recent warmer than normal years to replace historical colder years, the number of heating degree days that defines normal has declined over the last several years. 18 -------------------------------------------------------------------------------- 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 Gasrecognizes 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 $396,000and $389,000for the fiscal years ended September 30, 2021and 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 Gasis 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 Gasexpensed $217,000in deferred COVID costs incurred during fiscal 2021, and fully amortized the remaining $525,000balance 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 Gascan recover rising natural gas costs through the PGA mechanism as noted above; however, in times of rapidly increasing costs, the timing of recovery may lag. Increasing natural gas prices, especially in relation to other energy options, may lead to reductions in energy consumption through customer conservation or fuel switching in addition to the potential for rising bad debts related to customers inability to pay higher natural gas bills. Inflation affects the Company through increases in non-gas expenses such as labor costs, employee benefits, materials and supplies, contracted services and corporate insurance, among other areas. As the country emerges from the pandemic, issues such as supply chain delays, labor shortages and limited availability of key or critical supplies have put upward pressure on several categories of the Company's non-gas expenses. The Company recovers non-gas related costs through the non-gas portion of its tariff rates, which are adjusted through a non-gas rate application. Unlike the rate adjustments for the gas portion of rates which are done administratively, the non-gas rate application results in an inherent lag in non-gas expense recovery. Therefore, authorized non-gas rates may not keep pace with the rising costs during inflationary periods. Management must regularly evaluate the Company's operations, economic conditions and other factors to assess the need to apply for a non-gas rate adjustment. 19
Results of Operations
The analysis of the operating results is based on the consolidated operations of the Company, which are mainly associated with the utilities sector. Additional industry analysis is provided in areas where Midstream’s investment in affiliates is 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 to fiscal year 2020
The table below reflects operating revenues, volume activity and heating degree days. Operating Revenues Increase / Year Ended September 30, 2021 2020
(Decrease) Percentage Gas Utility
$ 75,045,103 $ 62,408,925 $ 12,636,17820 % Non Utility 129,676 666,466 (536,790 ) (81 )% Total Operating Revenues $ 75,174,779 $ 63,075,391 $ 12,099,38819 % Delivered Volumes Increase / Year Ended September 30, 2021 2020 (Decrease) Percentage Regulated Natural Gas(DTH) Residential and Commercial 6,773,819 6,419,031 354,788 6 %
Transport and interruption 3,135,710 3,938,143
(802,433 ) (20 )% Total Delivered Volumes 9,909,529 10,357,174 (447,645 ) (4 )% HDD 3,610 3,623 (13 ) (0 )% Total gas utility operating revenues for the year ended
September 30, 2021increased by 20% from the year ended September 30, 2020primarily 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 $1,215,000due to the ongoing investment in qualified SAVE infrastructure projects. Transportation and interruptible volumes, primarily driven by business activity rather than weather, declined by 20% due to a single multi-fuel customer that switched its primary fuel from natural gas to an alternate energy source in response to rising natural gas prices. In early fiscal 2020, this same customer switched from another energy source to natural gas as its primary fuel due to the favorable pricing of natural gas. Excluding the multi-fuel customer's usage from both periods, total transportation and interruptible volumes would have increased by 3% on a comparative basis. Non-utility revenues decreased due to the completion of a significant long-term contract in fiscal 2020. 20
Gross Utility Margin Year Ended September 30, 2021 2020 Increase Percentage Gas Utility Revenues
$ 75,045,103 $ 62,408,925 $ 12,636,17820 % Cost of Gas - Utility 35,179,842 23,949,481 11,230,361 47 % Gross Utility Margin $ 39,865,261 $ 38,459,444 $ 1,405,8174 % Gross utility margin increased over the prior fiscal year primarily as a result of the aforementioned higher SAVE revenues and increase in residential and commercial volumes and customer base charges more than offsetting the reduction in transportation and interruptible deliveries. Total volumetric margin increased for the reasons mentioned above as the increase in residential and commercial DTH sales more than offset the decline in lower-margin interruptible and transportation volumes. The growth in customer base charge revenues reflect a combination of customer additions and the continuation of service to delinquent customers as a result of the disconnection moratorium, which ended August 30, 2021. The changes in the components of the gross utility margin are summarized below: Years Ended September 30, 2021 2020 Increase / (Decrease) Customer Base Charge $ 14,563,274 $ 14,413,709$ 149,565 SAVE Plan 2,487,299 1,272,070 1,215,229 Volumetric 21,188,794 21,091,007 97,787 WNA 1,196,499 1,192,715 3,784 Carrying Cost 395,626 388,607 7,019 Other Revenues 33,769 101,336 (67,567 ) Total $ 39,865,261 $ 38,459,444$ 1,405,817 Operations and Maintenance Expense - Operations and maintenance expense decreased by $1,703,874or 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 $317,000in 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 Gasaccelerated the recovery of the remaining $525,000balance of ESAC assets in September 2020as a result of the earnings test performed by the Company. Bad debt expense declined by $964,000due to the application of more than $400,000in CARES Act funds to eligible COVID-19 impacted customers with past due balances and the pending receipt of $859,000in 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 $258,000on a nearly $3 millionreduction in capital expenditures related to project timing. 21 --------------------------------------------------------------------------------
General taxes – General taxes increased by
Depreciation – Depreciation expense increased by
Equity in Earnings of Unconsolidated Affiliate - The equity in earnings of the MVP investment decreased by
$3,147,320as 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 2021resulting 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 $275,850primarily due to a $449,000decrease in the non-service cost components of net periodic benefit costs partially offset by $207,000reduction in the equity portion of AFUDC on Roanoke Gas'two gate stations that will interconnect with the MVP. Roanoke Gastemporarily stopped recognizing AFUDC effective January 2021until 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.
reduction in interest expense attributable to the repayment of rates for fiscal 2020.
Midstream's interest expense decreased by
$128,558as 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 $6,900,000increase 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 $780,000due to the significant reduction in pre-tax earnings related to AFUDC from the MVP investment. The majority of the remaining $680,000difference 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 $10,102,062compared to $10,564,534for fiscal 2020. Basic and diluted earnings per share were $1.22in fiscal 2021 compared to $1.30in fiscal 2020. Dividends declared per share of common stock were $0.74in fiscal 2021 compared to $0.70in fiscal 2020.
Capital resources and liquidity
Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company's primary capital needs are the funding of its capital projects, investment in MVP, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its operating cash flows, credit availability under short-term and long-term debt agreements and proceeds from the sale of its common stock. 22
Cash and cash equivalents increased by approximately
Cash Flow Summary Years Ended September 30, 2021 2020 Net cash provided by operating activities
$ 11,568,108 $ 12,823,903Net cash used in investing activities (25,849,237 ) (30,721,011 ) Net cash provided by financing activities 15,508,380
16 556 826
Net increase (decrease) in cash and cash equivalents
$ (1,340,282 )
Cash flow generated 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 millionfrom 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 elements of operating cash flow:
Years Ended September 30, Increase Cash Flows From Operating Activities: 2021 2020 (Decrease) Net Income
$ 10,102,062 $ 10,564,534 $ (462,472 )Non-cash adjustments: Depreciation 8,669,977 8,126,427 543,550 Equity in earnings (1,667,554 ) (4,814,874 ) 3,147,320 AFUDC (55,981 ) (330,208 ) 274,227 Allowance for doubtful accounts (461,130 ) 592,398 (1,053,528 ) ESAC assets - 1,022,195 (1,022,195 ) Changes in working capital and regulatory assets and liabilities: Accounts receivable (1,084,726 ) (141,482 ) (943,244 ) Gas in Storage (2,158,709 ) 739,546 (2,898,255 ) Prepaid income taxes (2,457,327 ) 510,357 (2,967,684 ) Accounts payable and accrued expenses 2,862,861 659,276 2,203,585 Deferred Taxes 106,188 1,327,655 (1,221,467 ) Change in over (under) collection of gas costs (3,314,446 ) (1,895,555 ) (1,418,891 ) Rate refund - (3,827,589 ) 3,827,589 WNA (609,888 ) 1,171,342 (1,781,230 ) Non-current regulatory liabilities 2,367,512 - 2,367,512 Other (730,731 )
(880 119) 149 388 Net cash flow generated by operating activities
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, $1.4and $2.9 millionyear over year, respectively. Income tax refunds not yet received, associated with the R&D credit study conducted by a third party consultant, caused prepaid income taxes to increase significantly year over year, resulting in a decrease in operating cash of $3 million. See Note 8 for more information regarding the R&D tax credit. 23
-------------------------------------------------------------------------------- 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 millionin operating cash year over year. As there was no rate refund in fiscal 2021, operating cash improved $3.8 million.
Other significant non-monetary changes include
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 millionand $22.9 millionin fiscal 2021 and 2020, respectively. Roanoke Gasrenewed 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 Gascontinues 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 millionfor Midstream's participation in the LLC. Midstream's total expected funding requirement increased to between $60and $62 millionas 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 Investmentin Mountain Valley Pipeline section below.
Cash flow generated 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 millionand $16.6 millionin 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 millionto finance its investment in MVP. The Company also realized $3.3 millionfrom the issuance of common stock through its ATM program and $1.6 millionfrom the issuance of stock through DRIP activity and the exercise of options. Cash out-flows for dividend payments exceeded $6.0 millionas the annualized dividend rate increased from $0.70to $0.74per share. The Company's consolidated capitalization was 41.5% equity and 58.5% long-term debt at September 30, 2021, exclusive of unamortized debt expense. This compares to 41.7% equity and 58.3% long-term debt at September 30, 2020. 24 -------------------------------------------------------------------------------- On October 29, 2021Midstream entered into an unsecured promissory note in the principal amount of $8 millionwith 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 millionto $33 millioneffective with the new promissory note. All other terms of the Third Amendment to Credit Agreement remain unchanged. On September 24, 2021, Roanoke Gasentered into an unsecured Delayed Draw Term Note in the principal amount of $10 millionwith 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 millioneach on April 1, 2022and October 1, 2022, respectively. On August 20, 2021, Roanoke Gasentered into an unsecured Delayed Draw Term Note in the principal amount of $15 millionwith 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 Gasrenewed its unsecured line-of-credit agreement for a two-year term expiring March 31, 2023with 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 millionto $40 million. On December 6, 2019, Roanoke Gasentered 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 Gashas private shelf agreements with two different financial institutions. The first agreement, as amended, provides for the issuance of up to $40 millionin unsecured notes in addition to the $28 millionpreviously issued. This shelf agreement will expire on December 6, 2022unless extended. The second agreement, effective September 30, 2020, provides for the issuance of up to $70 millionin 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 SECutilizing 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 provisions
The Company has no off-balance sheet arrangements as defined in Regulation SK, Section 303 (a) (4) (ii).
Recent construction activity has been limited based on legal and regulatory challenges. Although certain permits and authorizations were received in the fourth quarter of fiscal 2020 and the first quarter of fiscal 2021, there remain pending challenges and authorization requests impacting current progress. 25 -------------------------------------------------------------------------------- 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, Pittsburghand Norfolk Districts of the U.S. Army Corps of Engineers( Army Corps) that requests an individual permit from the Army Corpsto 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 FERCauthority 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 Corpsfor additional time to address the applications, and in late June 2021, the Army Corpsgranted the WVDEP and the VADEQ additional review time through November 29, 2021and December 31, 2021, respectively. In early June 2021, the FERCissued a notice of schedule for the LLC's CPCN amendment application. FERCissued its environmental assessment August 13, 2021. Given that the expected permitting timelines for both the FERCand the Army Corpsremain 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 FERCto 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 Forestfrom the Bureau of Land Management, the U.S. Forest Serviceand the FERC; (ii) continue to have available the orders previously issued by the FERCmodifying its prior stop work orders and extending the LLC's prescribed time to complete the MVP project; (iii) timely receive authorization from the FERCto complete construction work in the portion of the project route currently remaining subject to the FERC'sprevious 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 Servicefor 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 Gascontinues the suspension of AFUDC accruals on its two gate stations that will interconnect with the MVP until such time as construction activities resume on the respective gate stations. Management conducted an assessment of its MVP investment in accordance with the provisions of ASC 323, Investments - Equity Method and Joint Ventures. This assessment included a third-party valuation. As a result of its evaluation, management has concluded that the investment is not currently impaired as of September 30, 2021. Furthermore, the LLC has conducted its own evaluation of the project and also concluded that no impairment exists as of September 30, 2021. Management will continue monitoring the status of the project for circumstances that may lead to future impairment, including any significant delays or denials of necessary permits and approvals. If necessary, the amount and timing of any future impairment would be dependent on the specific circumstances at the time of evaluation. 26
April 2018, the LLC announced the MVP Southgate project and submitted Southgate's certificate application to the FERCin November 2018. The Final Environmental Impact Statement for the project was issued on February 14, 2020. In June 2020, the FERCissued the CPCN for the MVP Southgate; however, the FERC, while authorizing the project, directed the Office of Energy Projectsnot 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 Projectslifts 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 a borrowing capacity of
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 Gasan annualized non-gas rate increase of $7.25 millionand providing for a 9.44% return on equity and directing the write-off of $317,000of 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 millionin 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 Gaswith 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 Gasrecognized a total of $55,981in AFUDC, $41,978and $14,003of equity and debt carrying costs, respectively. Beginning January 2021, Roanoke Gastemporarily 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 Gasreceived $403,000in 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 Gasreceived notification from the SCC that its application for ARPA funds has been approved. According to the communication, the Company will receive $858,556based on arrearage balances as of August 31, 2021. The pending receipt of these funds were considered in the valuation of the estimated allowance for uncollectibles as of September 30, 2021. 27 -------------------------------------------------------------------------------- In April 2020, the SCC issued an order allowing regulated utilities in Virginiato defer certain incremental, prudently incurred costs associated with the COVID-19 pandemic and to apply for recovery at a future date. Roanoke Gasdeferred certain COVID-19 related costs throughout fiscal 2021. Based on Roanoke Gas'spreliminary 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 Gascontinues 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 2021through September 2022. In its application, Roanoke Gasrequested 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 millionin annual revenues, an increase of approximately $1.1 millionfrom the existing SAVE Rider rates. The Company received a final order on August 25, 2021in which the SCC approved the Company's requested revenue requirement.
Critical accounting conventions and estimates
The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in
the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company's financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and professional judgments. Actual results may differ significantly from these estimates and assumptions. The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical. Regulatory accounting - The Company's regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the consolidated balance sheet and recorded as expenses in the consolidated statements of income and comprehensive income when such amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the consolidated balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred. The write-downs of the COVID asset and ESAC assets are consistent with the provisions of ASC No 980. Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates is adjusted quarterly, or more frequently if necessary, through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. 28
-------------------------------------------------------------------------------- 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
$1,191,227and $1,041,518as of September 30, 2021and 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 $242,010as of September 30, 2021. The Company is committed to working with its customers during these difficult times by providing extended payment terms and assisting customers in finding other sources of financial aid. With rising natural gas prices and lingering economic effects from the moratorium and COVID, bad debt concerns will continue into fiscal 2022. Pension and Postretirement Benefits - The Company offers a pension plan and a postretirement plan to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 9 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the consolidated balance sheet. 29 -------------------------------------------------------------------------------- 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 Treasuryincreased 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, 2017would 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 $717,197were 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 millionover the last three years, while liabilities increased by $8.8 millionduring the same period primarily due to a decline in the discount rate for determining the liability from 4.11% at September 30, 2018to 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 2017when 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 millionand liabilities increased by $0.6 millionover the last three-year period. As the number of participants in the postretirement plan continue to decline through attrition, management will continue to monitor and evaluate the asset allocation and adjust as warranted. 30
A summary of the funded status of pension plans and supplemental pension plans is presented below:
Funded Status –
Total Benefit Obligation
$ 37,654,468 $ 16,796,849 $ 54,451,317Fair value of assets 38,914,107 15,882,342 54,796,449 Funded status $ 1,259,639 $ (914,507 ) $ 345,132
Funded Status –
Total Benefit Obligation
$ 39,998,002 $ 17,925,409 $ 57,923,411Fair value of assets 37,657,631 14,116,253 51,773,884 Funded status $ (2,340,371 ) $ (3,809,156 ) $ (6,149,527 )The Company annually evaluates the returns on its targeted investment allocation model as well as the overall asset allocation of its benefit plans. Understanding the volatility in the markets, the Company reviews both plans' potential long-term rate of return with its investment advisors to determine the rates used in each plan's actuarial assumptions. Under the current allocation model for the pension plan, management lowered the long-term rate of return assumption from 5.40% in fiscal 2021 to 4.75% in fiscal 2022 based on the change in the current equity allocation of the pension plan assets and the lower rate of return expected on the fixed income investments. The long-term rate of return was virtually unchanged for the postretirement plan at 4.25% as the asset allocation remains at 50% equity and 50% fixed income. Management will continue to re-evaluate the return assumptions and asset allocation and adjust both as market conditions warrant. Management estimates that, under the current provisions regarding defined benefit pension plans, the Company will have no minimum funding requirements next year. However, the Company currently expects to contribute approximately $500,000to its pension plan and $400,000to its postretirement plan in fiscal 2022. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions and minimize PBGC premiums. The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant. Increase in Projected Change in Increase in Benefit Actuarial Assumptions - Pension Plan Assumption Pension Cost Obligation Discount rate -0.25 % $ 143,000 $ 1,547,000Rate of return on plan assets -0.25 % 96,000 N/A Rate of increase in compensation 0.25 % 57,000 285,000 The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant. Increase in Accumulated Increase in Postretirement Change in Postretirement Benefit
Actuarial assumptions – Cost of post-retirement plan benefits
Obligation Discount rate -0.25 % $ 41,000
$ 652,000Rate of return on plan assets -0.25 % 35,000 N/A Medical claim cost increase 0.25 % 83,000 620,000 Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company's consolidated balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had three interest-rate swaps outstanding at September 30, 2021related 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. 31
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