RGC Resources - 10-Q quarterly report FY2018 Q1

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated-filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

See notes to condensed consolidated financial statements.

 

See notes to condensed consolidated financial statements.

 

See notes to condensed consolidated financial statements.

 

See notes to condensed consolidated financial statements.

UNAUDITED

RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. ("Resources" or the "Company") and its wholly owned subsidiaries: Roanoke Gas Company; Diversified Energy Company; and RGC Midstream, LLC.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Prior year share and per share data have been restated to reflect the three-for-two stock split effected in the form of a stock dividend effective March 1, 2017.

Other accounting standards that have been issued by the FASB or other standard-setting bodies are not currently applicable to the Company or are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

The State Corporation Commission of Virginia (“SCC”) exercises regulatory authority over the natural gas operations of Roanoke Gas. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service; safety standards; extension of service; and accounting and depreciation.

The method and timing of the refunds of both the excess deferred income taxes and the excess revenues will be determined by the SCC.

A summary of other comprehensive income and loss is provided below:

 

 

 

 

The Company has both a defined benefit pension plan (the “pension plan”) and a postretirement benefit plan (the “postretirement plan”). The pension plan covers substantially all of the Company’s employees and provides retirement income based on years of service and employee compensation. The postretirement plan provides certain health care and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and postretirement plan expense recorded by the Company is detailed as follows:

 

The table below reflects the Company's actual contributions made fiscal year-to-date and the expected contributions to be made during the balance of the current fiscal year.

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices in Level 1 that are either for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity for the asset or liability at the measurement date.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3).

 

The fair value of the interest rate swap is determined by using the counterparty's proprietary models and certain assumptions regarding past, present and future market conditions.

 

The fair value of long-term debt is estimated by discounting the future cash flows of the debt based on current market rates and corresponding interest rate spread.

 

ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources, Inc. (“Resources” or the “Company”) 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 2017 Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.

Forward-looking statements reflect the Company’s current expectations only as of the date they are made. The Company assumes no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations.

The three-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2018. The total revenues and margins realized during the first three months reflect higher billings due to the weather sensitive nature of the gas business.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 61,200 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

Resources also provides certain unregulated services through Roanoke Gas and its other subsidiaries. Such unregulated operations represent less than 2% of total revenues and margin of Resources on an annual basis.

The Company’s utility operations are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission ("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.

On December 22, 2017, the President signed into law the Tax Cuts and Job Act ("Tax Act") which provided sweeping changes to the federal income tax code. The most significant change for the Company is the reduction in the corporate maximum federal income tax rate from 35% to 21%. Under the provisions of the law, the Company will apply a lower corporate income tax rate to earnings beginning this current fiscal year in addition to the revaluation of its deferred tax assets and liabilities derived from a 34% corporate tax rate down to a 21% tax rate. For the unregulated operations of the Company, the effect of the change in tax rate and revaluation of the deferred taxes are reflected in income tax expense. However, for the regulated operations of Roanoke Gas, the net deferred tax liability adjustment of $11,742,274 was transferred to a regulatory liability for refund to customers. Likewise, Roanoke Gas also established a rate refund liability in the amount of $462,442 to record the estimated excess billings of customers during the first 3 months of the year as the Company's billing rates were designed to cover the operating expenses and a rate of return based on a federal tax rate of 34%. Additional information regarding the Tax Act and its impact on the Company is provided under the Tax Reform and Regulatory section below.

Over 98% of the Company’s annual revenues are derived from the sale and delivery of natural gas to Roanoke Gas customers. The SCC authorizes the rates and fees the Company charges its customers for these services. These rates are designed to provide the Company with the opportunity to recover its gas and non-gas expenses and to earn a reasonable rate of return for shareholders based on normal weather. Normal weather refers to the average number of heating degree days (an industry measure by which the average daily temperature falls below 65 degrees Fahrenheit) over the previous 30-year period.

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 a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy ("SAVE") adjustment rider.

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

The 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 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) for the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months ended December 31, 2017 and 2016, the Company accrued approximately $37,000 and $623,000 in additional revenue and margin for weather that was 1% and 15% warmer than normal, respectively.

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. The average unit price of gas in storage during the first three months of the current fiscal year was $0.31 per decatherm, or 11%, higher than the same period last year, as natural gas commodity prices were higher during the storage replenishment in 2017 as compared to 2016. However, the ratio of debt to equity has increased from last year, leading to a reduction in the ICC factor applied to inventory balances. The net result is a small increase in ICC revenues for the quarter.

The Company’s non-gas 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 rate application with the SCC utilizing historical information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved to include the additional investment in new non-gas rates. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure projects on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provide a return on rate base for the additional capital investments related to improving the Company's infrastructure until such time that a formal rate application is filed to incorporate this investment in the Company's non-gas rates. As the Company did not file for an increase in non-gas rates during the prior four years and the level of capital investment continues to grow, SAVE Plan revenues have continued to increase corresponding to the growth in qualified SAVE related infrastructure projects. The Company recorded approximately

$1,076,000 in SAVE Plan revenues for the three-month period ended December 31, 2017 compared to $881,000 for the same period last year. These SAVE Plan revenues will be included as part of the new non-gas base rates the next time the Company files for a non-gas rate increase.

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

 

Regulated natural gas margins from utility operations decreased from the same period last year primarily as a result of the reduction in regulated revenues of Roanoke Gas due to the estimated excess revenues reserve discussed in more detail above and under the Tax Reform and Regulatory section below. An increase in SAVE revenues of $195,824, along with increases in customer base charge, carrying cost and other gas revenues, offset a net reduction in WNA adjusted volumetric margins.

The components of and the change in gas utility margin are summarized below:

Operation and maintenance expenses decreased $194,717, or 6%, from the same period last year primarily related to reductions in benefit costs. Total employee benefit costs declined by $238,000. The benefit cost reduction includes a $177,000 decrease in the actuarially determined expenses, due to strong asset performance of both the the pension and the other post-retirement benefit plans, higher discount rate for valuing the benefit plan liabilities and a soft freeze of the pension plan. The remaining reduction in benefit costs is attributable to fewer total employees resulting from outsourcing customer support services in fiscal 2017. The net reduction in employee benefit costs combined with lower payroll were partially offset by higher contracted services, primarily due to customer service outsourcing.

General taxes increased by $25,248, or 6%, due to higher property taxes associated with increases in utility property partially offset by lower payroll taxes associated with fewer employees.

Depreciation expense increased by $159,150, or 10%, on a corresponding increase in utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $64,271, or 76%, due to the increasing investment in the Mountain Valley Pipeline ("MVP") project. The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). The equity in earnings amount will continue to increase as the investment in the MVP project continues. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.

Other expense, net increased by $12,420 primarily due to higher pipeline assessments.

Interest expense increased by $154,124, or 34%, due to a 27% increase in total average debt to finance the Company's capital budget and the Company's investment in MVP and rising interest rates on the Company's variable rate debt. The combination of the issuance of the new $8,000,000 notes and rising interest rates on the line-of-credit and Midstream notes served to increase the weighted-average effective interest rate from 3.41% in the first quarter of fiscal 2017 to 3.60% during the first fiscal quarter of 2018.

Income tax expense declined by $236,668, or 17%. The reduction in income taxes was a product of lower pre-tax income and the application of lower income tax rates due to the passage of the Tax Act. The combined state and federal tax rate declined from 37.96% to a blended 28.84% in fiscal 2018. The effective tax rate was 35.5% for the quarter compared to 38.1% for the same period last year. The effective tax rate for the current quarter is higher than the blended rate of 28.84% due to the valuation adjustments to the net deferred tax assets of the unregulated operations. These valuation adjustments to deferred taxes of the unregulated operations are charged to income tax expense in accordance with U.S. GAAP. Since the unregulated operations had a net deferred tax asset, the adjustment resulted in a charge to income tax expense of approximately $208,000. Excluding the $208,000 tax adjustment, the effective tax rate for the current quarter would have been 29%. The valuation adjustment to the net deferred tax liability of the regulated operations of Roanoke Gas was transferred to a regulatory liability as discussed in Note 3. Additional information regarding the Tax Act and its impact on the Company is provided under the Regulatory and Tax Reform sections below.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and 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 it 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's current quarter adjustments for the effect of the Tax Act includes estimates related to the revaluation of deferred income tax adjustments due to the blended income tax rate and the refund of excess billings to customers pending revisions to customer billing rates to be approved by the SCC. The Company believes these adjustments to be reasonable estimates of the financial effect of the tax change based on the best information available. These estimates will be adjusted as necessary once the SCC reviews and approves the Company's calculations and methodology. There have been no other changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, 2017.

Asset Management

Roanoke Gas uses a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the asset manager pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. The current agreement expires March 31, 2018. The Company has solicited bids for a new asset management agreement and is in the process of evaluating the proposals. The selection of the provider and execution of a new contract should be completed in the Company's second fiscal quarter.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the "LLC"). The purpose of the LLC is to construct and operate the MVP, a natural gas pipeline connecting Equitran's gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity, and in January 2018, FERC issued the first Notice to Proceed ("NTP"), which granted the LLC permission to begin construction on 93 access roads and 6 construction staging areas at defined locations in West Virginia as a precursor to construction of the pipeline and a second NTP approving the construction of compressor stations and interconnects in West Virginia . The LLC has submitted additional requests to FERC for NTP, which are pending approval at this time. The LLC has received the necessary federal permits and the required Virginia and West Virginia environmental agency permits. The managing partner of the LLC currently anticipates the in-service date for the MVP to be the end of calendar 2018.

Management believes the investment in the LLC will be beneficial for the Company, its shareholders and southwest Virginia. In addition to the potential returns from the investment in the LLC, Roanoke Gas will benefit from access to an additional source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage 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 risk 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 previously unserved areas in southwest Virginia.

The total project cost is anticipated to be approximately $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments were for the acquisition of land and materials related to the construction of the pipeline and other pre-construction costs. As the Notices to Proceed are granted, construction activities will escalate and more significant cash draws will be required. Initial funding for the investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a total of $25 million through 2020 with the balance coming from a combination of equity capital and debt.

A majority of the earnings from the investment in MVP relate to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately 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 the MVP will continue to grow at a steady pace until such time FERC issues their decision on the project. As the NTPs are received, construction on the pipeline will begin in earnest and both the investment in the MVP and the AFUDC will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline becomes operational would be derived from the fees charged for transporting natural gas through the pipeline.

Tax Reform and Regulatory

On December 22, 2017, the President signed into law the Tax Cuts and Job Act (the "Tax Act"), which provided sweeping changes to the federal income tax code. The most significant change to corporate entities was the reduction of the maximum federal income tax rate from 35% to 21%. Another significant change included the elimination of bonus depreciation for utilities in exchange for retaining full deductibility of utility related interest expense. There were several other changes to the tax code under the Tax Act that will have lesser effects on the Company.

As the tax rate change is effective January 1, 2018, the Company is using a blended tax rate calculated on the average number of days each tax rate is in effect during the current fiscal year. The Company's calculated federal tax rate during fiscal 2018 is 24.3% with an overall effective rate including state income tax of 28.84%. The overall effective rate will decline to 25.74% beginning in fiscal 2019.

The table below summarizes the impact to deferred income taxes, regulatory liability and income tax expense for the adjustment to deferred taxes.

As discussed above, Roanoke Gas' billing rates include a provision for federal income taxes at a 34% rate. Since the beginning of the current fiscal year, the Company has been recovering from its customers at the higher 34% tax rate as opposed to the blended 24.3% federal tax rate currently in effect. On January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for the excess revenues collected from Roanoke Gas customers. The directive remains in place until such time as the SCC approves and the Company implements, lower billing rates incorporating the lower federal income tax rate. Therefore, as of December 31, 2017, the Company recorded a reduction to revenue in the amount of $462,442, which corresponds to the reduction in income tax expense of the regulated operations, for the estimated excess revenue collected from customers since October 1, 2017. This estimated refund will be revised as necessary once the SCC reviews and approves the adjustment calculations and methodology for determining the refund. The method and timing of the refunds will be determined by the SCC.

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On September 28, 2017, the Company received SCC approval to implement new SAVE rates related to the proposed qualifying SAVE investments in calendar 2018. These new SAVE rates are designed to recover the additional expenses of the SAVE investment in addition to a return on the increase in rate base. The 2018 SAVE Plan continues to focus on the replacement of the pre-1973 plastic pipe and includes the replacement on one custody transfer station.

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 increased by $264,638 for the three-month period ended December 31, 2017, compared to a $467,177 decrease for the same period last year. The following table summarizes the sources and uses of cash:

 

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 and reductions in natural gas storage inventory during the first three months of the fiscal year. Cash flow from operating activities increased from the same period last year by $154,295, primarily due to a greater increase in over-collections on gas cost and a smaller increase in accounts receivable offset by a much smaller decrease in gas in storage. The smaller increase in accounts receivable is attributable to the large WNA accrual included in accounts receivable last year compared to the current quarter. The first quarter of last year was 15% warmer than normal which generated a WNA receivable of $622,959, while the current quarter was nearly normal with a WNA accrual of only $36,770. Removing the WNA accruals would have resulted in the current year having a bigger increase in accounts receivable. The smaller decrease in gas in storage is due to the beginning storage levels for the current quarter being below the same period last year resulting in additional gas delivered to storage in October and November 2017 to bring storage levels comparable to last year. A summary of the cash provided by operations is listed below:

Investing activities are generally composed of expenditures related to investment in the Company's utility plant projects, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and distribution system facilities, expanding its natural gas system to meet the demands of customer growth, as well as the continued investment in the MVP. The Company is continuing its focus on SAVE infrastructure replacement projects including the replacement of pre-1973 first generation plastic pipe and replacement of a natural gas transfer station. Total capital expenditures for the quarter were $4.3 million, which represented a $132,000 reduction from the same period last year. The small decrease is attributable in part to expenditures made last year related to the installation of an automated meter reading system ("AMR") completed in fiscal 2017. Although the current fiscal year capital budget does not include the AMR project, it does include increased activity on SAVE Plan projects as well as proposed system reinforcements and the installation of two interconnects to MVP with the Company's distribution system. Total capital expenditures are expected to exceed $20 million for fiscal 2018.

Investing cash flows also includes the Company's funding of its participation in the MVP, with a total cash investment of $1,232,980 for the three months ended December 31, 2017. The planned investment in the MVP is expected to accelerate significantly as FERC has issued two NTPs allowing for construction activity to begin in West Virginia. With construction slated to begin immediately and the remaining NTPs expected shortly, the Company anticipates an increase in its utilization of the Midstream credit facility. The Company also expects that the remaining funding for MVP to be provided by a combination of equity capital and additional debt. Management is currently evaluating the capital needs and timing related to its investment in MVP as well as the funding requirements for the Company's ongoing pipeline renewal and infrastructure improvements. Based on the results of this assessment and capital market conditions, the Company plans to determine the level of equity capital needed with an anticipated common stock offering sometime later this year.

Financing activities generally consist of long-term and line-of-credit borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flows provided by financing activities were $7,762,718 for the current period compared to $6,568,640 for the same period last year. The increase in financing cash flows is attributable to higher borrowings to finance the increased investment in MVP. The Company borrowed $1,264,000 under the Midstream credit facility during the current quarter compared to $508,000 for the same period last year. In addition, Roanoke Gas issued $8,000,000 in notes in October 2017 compared to a $7,000,000 bank note issued during the prior year. These notes were used to refinance part of the line-of-credit balance that provided capital expenditure bridge financing. The Company will continue to use the line-of-credit for bridge financing and will evaluate the need and timing to convert additional portions of this debt to more permanent financing. On October 2, 2017, the Company issued two 10-year unsecured notes in the aggregate principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. Interest is paid semi-annually on these notes in April and October of each year until the notes mature. The proceeds from these notes were used to refinance a portion of the line-of-credit balance into longer-term financing.

The Tax Act is expected to have liquidity impact to the Company. As mentioned under the Tax Reform and Regulatory section, the Tax Act eliminated the bonus depreciation deduction for taxes. Even though the federal tax rate is lower as a result of the Tax Act, the elimination of the accelerated deductions provided by bonus depreciation will increase taxable income more than offsetting the benefits of a lower tax rate. Furthermore, the excess revenues billed to Roanoke Gas customers, as well as the establishment of a regulatory liability for the adjustment to deferred income taxes, will be refunded to customers. The timing and method of returning these amounts back to customers has yet to be determined and will be subject to approval by the SCC. The settlement of these obligations could result in lower operating cash flows and/or increased borrowing.

On March 27, 2017, Roanoke Gas entered into a new revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2019, replacing the prior one-year agreement that expired on March 31, 2017. Except for the two-year term, the new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance on the note. The agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the agreement range from $10,000,000 to $30,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are considered to be non-current, as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-month period. As long as the multi-tiered borrowing limits under the line of credit remain above the outstanding balance over the succeeding 12 month period, the line-of-credit balance is classified as non-current. However, the borrowing limits on the line-of-credit decline to $17,000,000 effective March 1, 2018, thereby resulting in $54,377 of the line-of-credit balance to be reclassified to a current liability. The Company is currently in discussions to extend the current agreement by one year prior to the end of March when the outstanding balance on the line-of-credit would be classified as current. The Company anticipates being able to extend or replace the line-of-credit agreement; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.

At December 31, 2017, the Company’s consolidated long-term capitalization including the line-of-credit was 47% equity and 53% debt.

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At December 31, 2017, the Company had $17,054,377 outstanding under its variable rate line-of-credit with an average balance outstanding during the three-month period of $13,425,938. The Company also had $7,576,200 outstanding under a 5-year variable-rate term credit facility. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable-rate debt outstanding during the period would have resulted in an increase in annual interest expense of approximately $52,500. The Company's other long-term debt is at fixed rates or is hedged with an interest rate swap.

Commodity Price Risk

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

At September 30, 2017, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 2,117,098 decatherms of gas in storage, including LNG, at an average price of $3.26 per decatherm, compared to 1,959,449 decatherms at an average price of $2.97 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, as any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the PGA mechanism.

ITEM 4 – CONTROLS AND PROCEDURES

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

None.

ITEM 1A – RISK FACTORS

No changes.

ITEM 2 – UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 – OTHER INFORMATION

None.

ITEM 6 – EXHIBITS

 

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned there unto duly authorized.