Forward-Looking Statements This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, Resources may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management's current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company's actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company's forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company's business include, but are not limited to those set forth in the following discussion and within Item 1A "Risk Factors" in the Company's 2019 Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company's control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company's documents or news releases, the words, "anticipate," "believe," "intend," "plan," "estimate," "expect," "objective," "projection," "forecast," "budget," "assume," "indicate" or similar words or future or conditional verbs such as "will," "would," "should," "can," "could" or "may" are intended to identify forward-looking statements. Forward-looking statements reflect the Company's current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. The three-month earnings presented herein should not be considered as reflective of the Company's consolidated financial results for the fiscal year endingSeptember 30, 2020 . The total revenues and margins realized during the first three months reflect higher billings due to the weather sensitive nature of the natural gas business. Overview Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 62,000 residential, commercial and industrial customers inRoanoke, Virginia and the surrounding localities through itsRoanoke Gas subsidiary. Resources also invests in the Mountain Valley Pipeline, an interstate pipeline currently under construction, as a more than 1% participant through its Midstream subsidiary in addition to providing certain unregulated services through itsRoanoke Gas subsidiary. The unregulated operations ofRoanoke Gas represent less than 2% of total revenues of Resources on an annual basis. The Company's utility operations are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from theDepartment of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines.FERC regulates the prices for the transportation and delivery of natural gas to the Company's distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific. Over 98% of the Company's annual revenues, excluding equity in earnings of MVP, are derived from the sale and delivery of natural gas toRoanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. OnOctober 10, 2018 ,Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates.Roanoke Gas implemented the non-gas rates contained in its rate application for natural gas service rendered to customers on or afterJanuary 1, 2019 . These non-gas rates are subject to refund pending audit, hearing and a final order issued by the SCC. Both the SCC staff and the hearing examiner on the case have completed their work and issued their reports in June and November, respectively. OnJanuary 24, 2020 , the SCC issued the final order on the general rate application, grantingRoanoke Gas an annualized increase in the non-gas base rates of$7.25 million . The order also directed the Company to write-down$317,191 of ESAC assets that were not subject to recovery under the final order. The Company has revised its rate refund accrual as ofDecember 31, 2019 to reflect the rate award and ESAC write-down. The Company has designed non-gas 22
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rates to reflect the increased revenues and has submitted the new rates to the SCC for approval. Such rates may be adjusted by the SCC staff, which could result in minor changes to the rate refund reserve. The Company will continue to record a rate refund until such time as the final non-gas rates are approved and the refund to customers is completed. In fiscal 2019, the Company completed the transition to the 21% federal statutory income tax rate as a result of the TCJA that was signed into law inDecember 2017 . Between the enactment of the new tax rates and the Company's implementation of new non-gas rates effectiveJanuary 1, 2019 , the Company was recovering revenues based on a 34% federal income tax rate rather than a 21% federal tax rate. As a result, during this period, the Company recorded a provision for refund related to estimated excess revenues collected from customers for the difference in non-gas rates derived under the lower federal tax rate and the 34% rate in effect. For the three-month period endedDecember 31, 2018 , the Company accrued a refund of approximately$524,000 related to these excess revenues for the effect of the different federal income tax rates on the non-gas billing rates. Beginning inJanuary 2019 ,Roanoke Gas incorporated the effect of the 21% federal income tax rate with the implementation of new non-gas base rates, as filed in its general rate application, and began refunding the excess revenues associated with the change in the tax rate. The refund of the excess revenues related to the reduction in the federal income tax rate was completed inDecember 2019 . The Company also recorded a regulatory liability related to the excess deferred income taxes on the regulated operations ofRoanoke Gas . These excess deferred income taxes are being refunded to customers over a 28-year period. Additional information regarding the TCJA and non-gas base rate award is provided under the Regulatory and Tax Reform section below. As the Company's business is seasonal in nature, volatility in winter weather and the commodity price of natural gas can impact the effectiveness of the Company's rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of variations in weather and the cost of natural gas, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include the SAVE Rider, WNA, ICC revenue and PGA.The Company's non-gas base rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal non-gas rate application with the SCC utilizing historical and proforma information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas base rates currently in place, while the investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved. The SAVE Plan and Rider provides a mechanism through which the Company may recover on a prospective basis the related depreciation and expenses and provides a return on rate base for the related additional qualified capital investments until such time that a formal rate application is filed. As the Company has made significant SAVE qualified expenditures since the last non-gas base rate increase in 2013, SAVE Plan revenues have continued to increase each year. With the filing of the non-gas rate application, the SAVE Rider reset effectiveJanuary 2019 as the prior revenues associated with the qualified SAVE Plan infrastructure investments were incorporated into the non-gas rates. Accordingly, SAVE Plan revenues declined by approximately$1,027,000 for the three-month period endedDecember 31, 2019 compared to the same period last year. The WNA model reduces earnings volatility, related to weather variability in the heating season, by providing the Company a level of earnings protection when weather is warmer than normal and providing customers some price protection when the weather is colder than normal. The WNA is based on a weather measurement band around the most recent 30-year temperature average. Under the WNA, the Company recovers from its customers the lost margin (excluding gas costs) from the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months endedDecember 31, 2019 , the Company accrued approximately$167,000 in additional revenues under the WNA model for weather that was 4% warmer than normal compared to a reduction in revenue of approximately$157,000 for weather that was 3% colder than normal for the same period last year. The WNA year runs fromApril 1 to March 31 each year. Annually, following the end of the WNA year, customers are either billed for any margin shortfall or credited for any excess margin collected during the WNA year. The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with its natural gas inventory. Under this rate structure,Roanoke Gas recognizes revenue for the financing costs, or "carrying costs," of its investment in natural gas inventory. This ICC factor applied to the cost of inventory is based on the Company's weighted-average cost of capital including interest rates on short-term and long-term debt and the Company's authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted-average cost of capital. Total ICC revenues for the three months endedDecember 31, 2019 declined by approximately 14% from the same periods last year due to 23
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a combination of lower average price of gas in storage balances and a reduction in the ICC factor used in calculating these revenues. The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is a pass-through cost and is independent of the non-gas base rates of the Company. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, or more frequently if necessary, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its tariff rates depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as those amounts are reflected in customer billings. Cyber attacks are a constant threat to businesses and individuals. The Company remains focused on these threats and is committed to safeguarding its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions or compromise information. Management believes it has taken reasonable security measures to protect these systems from cyber attacks and similar incidents; however, there can be no guarantee that an incident will not occur. In the event of a cyber incident, the Company will execute its Security Incident Response Plan. The Company maintains cyber insurance to mitigate financial exposure that may result from a cyber incident. Results of Operations Three Months EndedDecember 31, 2019 : Net income increased by$1,572,774 for the three months endedDecember 31, 2019 , compared to the same period last year. Quarterly performance improved significantly due to the impact of the rate increase and the earnings on the MVP investment, offsetting increases in operation and maintenance costs and interest expense. The tables below reflect operating revenues, volume activity and heating degree-days. Three Months Ended December 31, Increase / 2019 2018 (Decrease) Percentage Operating Revenues Gas Utility$ 19,625,606 $ 21,036,581 $ (1,410,975 ) (7 )% Non utility 159,847 180,166 (20,319 ) (11 )% Total Operating Revenues$ 19,785,453 $ 21,216,747 $ (1,431,294 ) (7 )% Delivered VolumesRegulated Natural Gas (DTH) Residential and Commercial 2,249,256 2,366,074 (116,818 ) (5 )% Transportation and Interruptible 869,582 750,065 119,517 16 % Total Delivered Volumes 3,118,838 3,116,139 2,699 - % Heating Degree Days (Unofficial) 1,440 1,560 (120 ) (8 )% Total operating revenues for the three months endedDecember 31, 2019 , compared to the same period last year, declined due to a 35% reduction in the commodity price of natural gas and reduced SAVE Plan revenue more than offsetting the net non-gas rate increase. The average commodity price of natural gas for the current quarter was$2.50 per decatherm compared to$3.85 per decatherm for the same period last year. Low natural gas prices are expected to continue due to abundant supplies, with futures prices for the remainder of the fiscal year averaging between$1.90 and$2.20 a decatherm. In addition, SAVE Plan revenues declined by$1,026,899 as the SAVE Rider resetJanuary 1, 2019 , and all qualifying SAVE Plan investments were included in rate base used to derive the new non-gas base rates. The prior year SAVE Plan revenues represented 5 years of SAVE investment while current year revenues represent only one year of qualifying investment. As noted above, the Company placed new non-gas base rates into effect for natural gas service rendered on or afterJanuary 1, 2019 , subject to refund. The new rates incorporated revenues related to SAVE Plan activities throughDecember 2018 , as well as recovery of higher expenses and non-SAVE infrastructure additions since the last rate application. Total revenues have been adjusted by an estimate for refunds based on the SCC's final order. Net residential and commercial volume deliveries declined by 116,818 24
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decatherms on weather that was 8% warmer than normal. After adjusting for WNA, total residential and commercial volumes effectively increased by nearly 26,000 decatherms or more than 1%. In addition, the prior year included a reserve of$523,881 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. No such reserve was recorded during the current quarter due to the implementation of new non-gas base rates inJanuary 2019 . Non-utility revenue declined due to do lower demand for services during the quarter. The Company's operations are affected by the cost of natural gas, as reflected in the condensed consolidated income statement under the line item cost of gas - utility. The cost of natural gas is passed through to customers at cost, which includes commodity price, transportation, storage, injection and withdrawal fees with any increase or decrease offset by a correlating change in revenue through the PGA. Accordingly, management believes that gross utility margin, a non-GAAP financial measure defined as utility revenues less cost of gas, is a more useful and relevant measure to analyze financial performance. The term gross utility margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. Therefore, the following discussion of financial performance will reference gross utility margin as part of the analysis of the results of operations. Three Months Ended December 31, Increase / 2019 2018 (Decrease) Percentage Gas Utility Margin Utility Revenues$ 19,625,606 $ 21,036,581 $ (1,410,975 ) (7 )% Cost of Gas 8,177,806 11,906,459 (3,728,653 ) (31 )% Gas Utility Margin$ 11,447,800 $ 9,130,122 $ 2,317,678 25 % Gross utility margins increased from the same period last year primarily as a result of the implementation of higher non-gas base rates effectiveJanuary 1, 2019 . The non-gas base rate increase, net of estimated refund, accounted for more than$2,000,000 of the increase in margin through the customer base charge and the volumetric component in addition to customer growth. SAVE Plan revenues declined by$1,026,899 as all related SAVE investments were incorporated into the new non-gas base rates. WNA margin increased by nearly$324,000 as weather moved from colder than normal in the prior year to warmer than normal during the current quarter. Furthermore, the prior year included a reserve for excess revenues attributable to the reduction in income tax rates. The current year has no such adjustment as the new non-gas rates incorporate the effect of lower federal income tax rates. When the Company filed its application for an increase in non-gas base rates, approximately 80% of the increase was reflected in the customer base charge to correspond with the fixed monthly billing under the SAVE Rider. The SCC staff report on the rate application recommended that only 20% of the non-gas base rate increase be allocated to customer base charge. The hearing examiner's report and subsequent final order supported this position. As a result, inJune 2019 , the Company revised its rate refund assumptions to reflect a rate design that would allocate 80% of the non-gas base rate increase to volumetric component and 20% to the customer base charge component. This revision results in an even greater level of earnings during the weather sensitive heating season due to the increased allocation to the weather sensitive component of non-gas rates and lower earnings in the non-heating season due to lower fixed rate revenues. The components of and the change in gas utility margin are summarized below: Three Months Ended December 31, 2019 2018 Increase / (Decrease) Customer Base Charge$ 3,580,749 $ 3,117,995 $ 462,754 Carrying Cost 155,907 181,635 (25,728 ) SAVE Plan 180,613 1,207,512 (1,026,899 ) Volumetric 7,303,843 5,259,338 2,044,505 WNA 166,597 (157,334 ) 323,931 Other Gas Revenues 60,091 44,857 15,234 Excess Revenue Refund - (523,881 ) 523,881 Total$ 11,447,800 $ 9,130,122 $ 2,317,678 25
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Operation and maintenance expenses increased by$395,471 , or 11%, from the same period last year related to the write-off of a portion of the ESAC regulatory assets, amortization of the remaining regulatory assets and higher corporate insurance costs, partially offset by higher capitalized overheads. Beginning inJanuary 2019 , concurrent with the implementation of new non-gas rates, the Company began amortizing certain regulatory assets for which recovery was included in the rate application. A total of$129,000 was charged to expense related to the amortization of these assets. In addition, the SCC issued their final order on the Company's non-gas rate increase, which directed the Company to write-down$317,000 of ESAC assets that were not subject to recovery in the final order. Corporate insurance expense increased by$71,000 due to higher premiums related to increased liability limits and higher deductible reserves. Capitalized overheads increased by$85,000 primarily due to timing of LNG production related to facility upgrades at the plant during the summer. The remaining difference relates to a variety of small increases and decreases in expenses. The Company has plans to invest in several one-time maintenance projects during the balance of the current fiscal year, which may result in a significant increase in operation and maintenance expenses when compared to fiscal 2019. General taxes increased by$35,348 , or 7%, associated with higher property and payroll taxes. Property taxes continue to increase corresponding to higher utility property balances related to ongoing infrastructure replacement, system reinforcements and customer growth. Depreciation expense increased by$83,030 , or 4%, on an increase in utility plant investment. Equity in earnings of unconsolidated affiliate increased by$531,037 , or nearly double last year, due to AFUDC related to the increased construction activity and related investment in the MVP. Other income (expense), net increased by$31,757 primarily due to the non-service components of net periodic benefit costs per the requirements of ASC 715 as amended by ASU 2017-07, Compensation - Retirement Benefits, which requires that components of net periodic benefit costs other than service cost be presented outside of income from operations. Lower interest costs and higher return on plan assets offset increased amortization of the actuarial loss. See Note 11 - Employee Benefit Plans for a breakdown of the components of net periodic benefit costs. Interest expense increased by$268,403 , or 33%, due to a 34% increase in total average debt outstanding between quarters. The higher borrowing levels derived from the ongoing investment in MVP and financing expenditures in support ofRoanoke Gas' capital budget, partially offset by a slight reduction in the weighted average interest rate.Roanoke Gas interest expense increased by$142,614 as total average debt outstanding increased by$9,500,000 associated with the issuance of two separate debt issuances offset by reductions in the line-of-credit balances. The average interest rate increased from 3.69% to 3.72% between periods. Midstream interest expense increased by$125,789 as total average debt outstanding increased by$18,400,000 associated with cash investment in the MVP. The average interest rate decreased from 3.61% to 3.17% due to the decline in the variable interest rate on Midstream's credit facility and the entry into two separate notes with swap rates at 3.24% and 3.14%. Income tax expense increased by$539,374 corresponding to an increase in taxable income. The effective tax rate was 23.7% and 22.4% for the three month periods endedDecember 31, 2019 and 2018, respectively. Both periods included the amortization of excess deferred taxes. Critical Accounting Policies and Estimates The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted inthe United States of America . The amounts of assets, liabilities, revenues and expenses reported in the Company's consolidated financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and management judgments. Actual results may differ significantly from these estimates and assumptions. The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was derived and changes in the estimate are reasonably likely to occur from period to period. The Company had recorded an estimate for customer refunds related to the implementation of the new non-gas base rates effectiveJanuary 1, 2019 . InJanuary 2020 , the Company received the final order on the non-gas base rate application that defined the approved annual rate increase. Management developed revised non-gas rates based on the amount of the increase specified in the order; however, the actual rates approved could vary and result in minor adjustments to the reserve. 26
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The Company adopted 2016-02, Leases,, and subsequent guidance and amendments effectiveOctober 1, 2019 . The adoption of the ASU did not have a significant effect on the Company's results of operations, financial position or cash flows as the Company has only one lease, and management determined that the$25,000 value of the lease obligation to not be at a level material enough to warrant the the application of the guidance under the ASU. The Company does have easements for rights-of-way for its distribution system; however, all related costs associated with these have been paid in advance with no remaining obligation. There have been no other changes to the critical accounting policies as reflected in the Company's Annual Report on Form 10-K for the year endedSeptember 30, 2019 . Asset ManagementRoanoke Gas uses a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the asset manager paysRoanoke Gas a monthly utilization fee. In accordance with an SCC order issued in 2018, a portion of the utilization fee is retained by the Company with the balance passed through to customers through reduced gas costs.
OnOctober 1, 2015 , Midstream entered into an agreement to become a 1% member in the LLC. The purpose of the LLC is to construct and operate the MVP, aFERC -regulated natural gas pipeline connecting Equitran's gathering and transmission system in northernWest Virginia to theTransco interstate pipeline in south centralVirginia .
On
Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwestVirginia . In addition to Midstream's potential returns from its investment in the LLC,Roanoke Gas will benefit from an additional delivery source of natural gas into its distribution system. Currently,Roanoke Gas is served by two pipelines and an LNG peak-shaving facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the impact from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to currently unserved areas within the its certificated service territory. The MVP project is currently 90% complete. Activity on the MVP is limited this time of year to maintaining the infrastructure currently in place and restoration activities. The LLC is waiting on the reissuance of water crossing permits that were rescinded by the Fourth Circuit as well as the permit to cross a section of theJefferson National Forest . The LLC believes it has submitted all of the required documentation and information required to resolve the issues addressed by the Fourth Circuit. Currently, no action has been taken by the governmental agencies regarding the status, including the need for additional information, re-approval of the permits or rejection of the submissions. Until such time as approval is granted, activity on the pipeline will be limited as most of the pipeline work not encompassed in the revoked permits has been completed.
Assuming timely resolution of the permit issues above, the LLC projects an in-service date for the MVP in late calendar year 2020. The delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action that could provide for the recovery of these higher costs.
Midstream entered into the Third Amendment to Credit Agreement and amended the corresponding associated notes to increase the borrowing capacity under the credit facility from$26 million to$41 million and extend the maturity date toDecember 29, 2022 . Under the amended agreement and notes, Midstream should have the needed financing to meet its funding requirements in the MVP. If the rescinded permits are not re-issued and approved in a reasonable time period, both the cost of the MVP and Midstream's capital contributions will increase above current estimates and the in-service date will be extended beyond 2020. The current earnings from the MVP investment are attributable to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and construction of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. The level of investment in MVP, as well as the AFUDC, will continue to grow as construction activities continue. When the pipeline is completed and placed into service, AFUDC will cease. Once operational, earnings will be 27
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derived from capacity charges for utilizing the pipeline. Continued delays in the project could ultimately result in future earnings from the operation of the pipeline to be below the level of AFUDC recognized. In 2018, Midstream became a participant in Southgate, a project to construct a 74-mile pipeline extending from the MVP mainline at theTransco interconnect inVirginia to delivery points inNorth Carolina . Midstream is a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest approximately$2.5 million in the project. Midstream's participation in the Southgate project is for investment purposes only. The Southgate in-service date is currently targeted for 2021.
Regulatory and Tax Reform
OnOctober 10, 2018 ,Roanoke Gas filed a general rate case application requesting an annual increase in customer non-gas base rates of approximately$10.5 million . This application incorporated into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets, including all deferred ESAC related costs, and SAVE Plan investments and related costs previously recovered through the SAVE Rider. Approximately$4.7 million of the rate increase was attributable to moving the SAVE Plan related revenues into non-gas base rates. The new non-gas base rates were placed into effect for gas service rendered on or afterJanuary 1, 2019 , subject to refund, pending audit by SCC staff, hearing and final order by the SCC. OnJune 28, 2019 , the SCC staff issued their report and recommendations related to the rate application. The SCC staff report included a recommendation for a non-gas rate increase of approximately$6.5 million . Management reviewed and responded to the SCC staff report through submission of rebuttal testimony to certain proposed adjustments included in the report. At the hearing held onAugust 14 and 15, the Company addressed specific differences with SCC staff, including the proposed return on equity, the exclusion of certain infrastructure items from rate base, changes in customer class rate design and the exclusion of a portion of the regulatory assets associated with ESAC costs. OnNovember 19, 2019 , the hearing examiner issued his report, which was subsequently revised onNovember 26, 2019 . The revised report recommended an annual increase in non-gas base rates of more than$7.1 million in addition to allocating 80% of the increase to the volumetric component of rates with only about 20% associated with customer base charges. OnJanuary 24, 2020 , the SCC issued their final order providing for an annual increase in non-gas base rates of$7.25 million , while maintaining the allocation of 80% of the increase to the volumetric component of rates. The non-gas rate award provided for a 9.44% return on equity, but excluded from recovery at the current time, a return on the investment of two interconnect stations with the MVP. In addition, the final order directed the Company to write-off a portion of the ESAC assets that were excluded from recovery under the rate award. As a result, the Company expensed an additional$317,000 of ESAC assets above the normal amortization amount. Management has proposed a rate design to reflect the increase of$7.25 million in non-gas rates and has submitted these rates to the SCC for approval. The SCC may approve the rates as submitted or require changes to the rates, which could result in minor adjustments to the refund. Once the final rates have been approved, the Company will proceed with completing the refunds to its customers. Management has provided for a cumulative refund in the amount of$3,618,000 consistent with the SCC order based on the non-gas rates that are currently pending approval. The refund accrual will cease once the approved rates are placed into effect. The general rate case application incorporated the effects of tax reform, which reduced the federal tax rate for the Company from 34% to 21%.Roanoke Gas recorded two regulatory liabilities to account for this change in the federal tax rate. The first regulatory liability related to the excess deferred taxes associated with the regulated operations ofRoanoke Gas . AsRoanoke Gas had a net deferred tax liability, the reduction in the federal tax rate required the revaluation of these excess deferred income taxes to the 21% rate at which the deferred taxes are expected to reverse. The excess net deferred tax liability forRoanoke Gas' regulated operations was transferred to a regulatory liability, while the revaluation of excess deferred taxes on the unregulated operations of the Company were flowed into income tax expense in the first quarter of fiscal 2018. A majority of the regulatory liability for excess deferred taxes was attributable to accelerated tax depreciation related to utility property. In order to comply with theIRS normalization rules, these excess deferred income taxes must be flowed back to customers and through tax expense based on the average remaining life of the corresponding assets, which approximates 28 years. The corresponding balances related to the excess deferred taxes are included in the regulatory liability schedule in Note 14. The second regulatory liability relates to the excess revenues collected from customers. The non-gas base rates used since the passage of the TCJA inDecember 2017 throughDecember 2018 were derived from a 34% federal tax rate. As a result, the Company over-recovered from its customers the difference between the federal tax rate at 34% and the 24.3% blended rate in fiscal 2018 and 21% in fiscal 2019. To comply with an SCC directive issued inJanuary 2018 ,Roanoke Gas recorded a refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019. Starting with the implementation of the new non-gas base rates inJanuary 2019 ,Roanoke Gas began returning the excess revenues to customers over a 12-month period. The refund of the excess revenues was completed inDecember 2019 . 28
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The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. The original SAVE Plan was designed to facilitate the accelerated replacement of aging natural gas pipe by providing a mechanism for the Company to recover the related depreciation and expenses and return on rate base of the additional capital investment without the filing of a non-gas base rate application. Since the implementation and approval of the original SAVE Plan in 2012, the Company has modified, amended or updated it each year to incorporate various qualifying projects. InMay 2019 , the Company filed its most recent SAVE Plan and Rider, which continues the focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of a natural gas transfer station. InSeptember 2019 , the SCC approved the updated SAVE Plan and Rider effective with theOctober 2019 billing cycle. The new SAVE Rider is designed to collect approximately$1.1 million in annual revenues, an increase from the approximate$500,000 in annual revenues under the prior SAVE rates. With the inclusion of all previous SAVE investment throughDecember 31, 2018 into the rate application, the current SAVE Plan Rider reflects only the recovery of qualifying SAVE Plan investments made since the beginning ofJanuary 2019 . In addition, the SAVE application includes a refund factor to return approximately$543,000 in SAVE revenue over-collections from 2018, primarily resulting from the effect of the reduction in the federal income tax rate. Capital Resources and Liquidity Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company's primary capital needs are the funding of its utility plant capital projects, investment in the MVP, the seasonal funding of its natural gas inventories and accounts receivable and the payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and equity capital. Cash and cash equivalents decreased by$619,001 for the three-month period endedDecember 31, 2019 , compared to a$236,602 decrease for the same period last year. The following table summarizes the sources and uses of cash: Three Months Ended December 31, 2019 2018 Cash Flow Summary Net cash provided by (used in) operating activities$ 817,963 $ (2,300,174 ) Net cash used in investing activities (10,875,736 ) (15,833,528 ) Net cash provided by financing activities 9,438,772 17,897,100 Decrease in cash and cash equivalents$ (619,001 )
The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to increases in natural gas storage levels, rising customer receivable balances and construction activity. Cash flow provided by operations is primarily driven by net income, depreciation, reductions in natural gas storage inventory and increases in accounts receivable during the first three months of the fiscal year. Cash flow from operating activities increased by$3,118,137 over the same period last year primarily related to higher net income, net of equity in earnings, and the effect of lower natural gas prices on accounts receivable, gas in storage and accounts payable. Net income, excluding the non cash component of equity in earnings, contributed more than$1.0 million to the increase in cash provided by operations primarily as a result of the implementation of the non-gas base rate increase. However, significantly lower natural gas commodity prices have resulted in a reduced customer volumetric billing rate and lower total customer billings during the period more than offsetting the impact of the non-gas base rate increase. These lower commodity prices have resulted in smaller increases in both accounts receivable and accounts payable and their corresponding effect on operating cash. The decline in gas in storage was less during the current fiscal quarter compared to the same period last year due to a combination of lower average cost of gas in storage and less natural gas withdrawn from storage. A summary of the cash provided by operations is provided below: 29
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