| Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation —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 Resources and its wholly owned subsidiaries: Roanoke Gas, Diversified Energy and Midstream. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 60,700 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the SCC. Midstream is a wholly-owned subsidiary created primarily to invest in the Mountain Valley Pipeline project. Diversified Energy is inactive. The Company follows accounting and reporting standards established by the FASB and the SEC. On June 28, 2018, the SEC adopted amendments to the definition of a "smaller reporting company" that became effective on September 10, 2018. Under the rules for smaller reporting companies, certain disclosures required of larger public business entities are reduced or eliminated. As it has met the qualifications under the definition of smaller reporting company, the Company has used the smaller reporting company exception on a limited basis, but in most instances, disclosures have been consistent with the prior year. Rate Regulated Basis of 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 situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose 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 (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period which FASB ASC No. 980 no longer applied. Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2019 and 2018 are as follows: September 30 2019 2018 Assets: Current Assets: Regulatory assets: Accrued WNA revenues $ 569,558 $ 169,602 Under-recovery of gas costs — 922,898 ESAC assets 265,392 — Accrued pension and postretirement medical 602,674 293,000 Other deferred expenses 84,315 — Total current 1,521,939 1,385,500 Utility Property: In service: Other 11,945 11,945 Other Assets: Regulatory assets: Premium on early retirement of debt 1,712,808 1,826,995 Accrued pension and postretirement medical 9,414,695 5,704,718 ESAC assets 756,803 1,330,434 Other deferred expenses 294,547 — Total non-current 12,178,853 8,862,147 Total regulatory assets $ 13,712,737 $ 10,259,592 Liabilities and Stockholders' Equity: Current Liabilities: Regulatory liabilities: Over-recovery of gas costs $ 161,837 $ — Over-recovery of SAVE Plan revenues 574,181 670,034 Rate refund 3,827,588 1,320,167 Excess deferred income taxes 205,353 — Other deferred liabilities 108,644 — Total current 4,877,603 1,990,201 Deferred Credits and Other Liabilities: Asset retirement obligations 6,788,683 6,417,948 Regulatory cost of retirement obligations 11,892,352 11,163,981 Regulatory liabilities: Excess deferred income taxes 10,934,434 11,447,736 Total non-current $ 29,615,469 $ 29,029,665 Total regulatory liabilities $ 34,493,072 $ 31,019,866 As of September 30, 2019 , the Company had regulatory assets in the amount of $13,700,792 on which the Company did not earn a return during the recovery period. Utility Plant and Depreciation —Utility plant is stated at original cost and includes direct labor and materials, contractor costs, and all allocable overhead charges. The Company applies the group method of accounting, where the costs of like assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. In accordance with Company policy, expenditures for depreciable assets with a life greater than one year are capitalized, along with any upgrades or improvements to existing assets, when they significantly improve or extend the original expected useful life of an asset. Expenditures for maintenance, repairs, and minor renewals and betterments are expensed as incurred. The original cost of depreciable property retired is removed from utility plant and charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below. Utility plant is composed of the following major classes of assets: September 30 2019 2018 Distribution and transmission $ 209,171,339 $ 196,778,546 LNG storage 13,417,077 13,413,175 General and miscellaneous 15,198,548 14,662,599 Total utility plant in service $ 237,786,964 $ 224,854,320 Provisions for depreciation are computed principally at composite straight-line rates over periods ranging from 5 to 76 years . Rates are determined by depreciation studies which are required to be performed at least every 5 years on the regulated utility assets of Roanoke Gas. In September 2019, the SCC staff approved the Company's most recent depreciation study. The SCC directed the Company to implement the new rates retroactive to October 1, 2018. As a result of the new rates, the composite weighted-average depreciation rate was 3.31% for the year ended September 30, 2019 as compared to 3.32% and 3.29% for fiscal years ended September 30, 2018 and 2017, respectively. The implementation of the new depreciation rates reduced total depreciation expense by $32,570 for fiscal 2019 and increased net income by $24,187 or less than $0.01 per share. The composite rates are composed of two components, one based on average service life and one based on cost of retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. These retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for under the provisions of FASB ASC No. 980. Such amounts are classified as a regulatory liability. The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not identified any impairments which would have a material effect on the results of operations or financial condition. Asset Retirement Obligations —FASB ASC No. 410, Asset Retirement and Environmental Obligations , requires entities to record the fair value of a liability for an ARO when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded AROs for its future legal obligations related to purging and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain. The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the ARO is reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers. The following is a summary of the AROs: Years Ended September 30 2019 2018 Beginning balance $ 6,417,948 $ 6,069,993 Liabilities incurred 177,646 79,608 Liabilities settled (177,755 ) (126,907 ) Accretion 370,844 332,537 Revisions to estimated cash flows — 62,717 Ending balance $ 6,788,683 $ 6,417,948 Cash, Cash Equivalents and Short-Term Investments —From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the FDIC. The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2019 , the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Customer Receivables and Allowance for Doubtful Accounts —Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action. A reconciliation of changes in the allowance for doubtful accounts is as follows: Years Ended September 30 2019 2018 2017 Beginning balance $ 103,573 $ 99,456 $ 76,934 Provision for doubtful accounts 220,039 169,096 84,587 Recoveries of accounts written off 96,614 78,919 110,725 Accounts written off (309,483 ) (243,898 ) (172,790 ) Ending balance $ 110,743 $ 103,573 $ 99,456 Financing Receivables —Financing receivables represent a contractual right to receive money either on demand, or on fixed or determinable dates, and are recognized as assets on the entity’s balance sheet. Trade receivables, resulting from the sale of natural gas and other services to customers, are the Company's primary type of financing receivables. These receivables are short-term in nature with a provision for uncollectible balances included in the consolidated financial statements. Inventories —Natural gas in storage and materials and supplies inventories are recorded at average cost. Natural gas storage injections are priced at the purchase cost at the time of injection and storage withdrawals are priced at the weighted average cost of gas in storage. Materials and supplies are removed from inventory at average cost. Unbilled Revenues —The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2019 and 2018 were $1,236,384 and $911,657 , respectively. Income Taxes —Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file state and federal consolidated income tax returns. Debt Expenses —Debt issuance expenses are deferred and amortized over the lives of the debt instruments. The unamortized balances are offset against the carrying value of long-term debt. Over/Under-Recovery of Natural Gas Costs —Pursuant to the provisions of the Company’s PGA clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. On at least a quarterly basis, the Company files a PGA rate adjustment request with the SCC to increase or decrease the gas cost component of its rates, based 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 may either over-recover or under-recover its actual gas costs during the period. Any 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 deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12 -month period as amounts are reflected in customer bill. Fair Value —Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods into one of the following three broad levels: • 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 which require the Company to develop its own assumptions. 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). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 9 and 13. Use of Estimates —The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent 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. Excise and Sales Taxes —Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s consolidated income statements. Earnings Per Share —Basic EPS and diluted EPS are calculated by dividing net income by the weighted-average common shares outstanding during the period and the weighted-average common shares outstanding during the period plus dilutive potential common shares, respectively. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of basic and diluted EPS is presented below: Years Ended September 30 2019 2018 2017 Net Income $ 8,698,412 $ 7,297,205 $ 6,232,865 Weighted-average common shares 8,039,484 7,649,025 7,218,686 Effect of dilutive securities: Options to purchase common stock 39,466 46,687 37,360 Diluted average common shares 8,078,950 7,695,712 7,256,046 Earnings Per Share of Common Stock: Basic $ 1.08 $ 0.95 $ 0.86 Diluted $ 1.08 $ 0.95 $ 0.86 Business and Credit Concentrations — The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories. No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable. Roanoke Gas currently holds the only franchises and CPCNs to distribute natural gas in its service area. These franchises are effective through January 1, 2036 . The Company's current CPCNs in Virginia are exclusive and are intended for perpetual duration. Roanoke Gas is served directly by two primary pipelines that provide all of the natural gas supplied to the Company’s customers. Depending upon weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company. Derivative and Hedging Activities —FASB ASC No. 815, Derivatives and Hedging , requires the recognition of all derivative instruments as assets or liabilities in the Company’s consolidated balance sheet and measurement of those instruments at fair value. The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company may hedge against include the price of natural gas and the cost of borrowed funds. The Company historically has entered into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the consolidated balance sheets with the offsetting entry to either under- or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of prudent costs associated with natural gas purchases. At September 30, 2019 and 2018 , the Company had no outstanding derivative instruments for the purchase of natural gas. The Company has three interest rate swaps associated with its variable rate debt. Roanoke Gas has a swap on its $7,000,000 term note that effectively converts the variable interest rate into a 2.30% fixed interest rate. In June 2019, Midstream entered into two variable-rate term notes in the amount of $14,000,000 and $10,000,000 with corresponding swap agreements to convert the variable interest rates into fixed rates of 3.24% and 3.14% , respectively. All swaps qualify as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swaps were deemed ineffective during the period. See Notes 7 and 13 for additional information on the swaps and fair value. Non-Cash Activity — A non-cash decrease in unconsolidated affiliate and corresponding decrease in capital contributions payable of $5,117,942 occurred for the fiscal year ended September 30, 2019, while an increase in investment in unconsolidated affiliate and corresponding increase in capital contributions payable of $9,087,262 and $767,710 occurred for the fiscal years ended September 30, 2018 and 2017, respectively. Stock Issue — In March 2018, the Company issued 700,000 shares of common stock resulting in proceeds of $15,109,541 net of underwriting and other expenses. The Company issued the common shares to strengthen its balance sheet by increasing the equity component of its total capitalization ratio. The net proceeds were invested in Roanoke Gas to supplement the funding of its infrastructure improvement and replacement programs. Other Comprehensive Income (Loss) — A summary of other comprehensive income is provided below: Before Tax Amount Tax (Expense) or Benefit Net of Tax Amount Year Ended September 30, 2019: Interest rate swap: Unrealized losses $ (1,117,595 ) $ 287,669 $ (829,926 ) Transfer of realized gains to interest expense (87,309 ) 22,474 (64,835 ) Net interest rate swap (1,204,904 ) 310,143 (894,761 ) Defined benefit plans: Net loss arising during period $ (962,612 ) $ 247,777 $ (714,835 ) Amortization of actuarial gains (10,305 ) 2,652 (7,653 ) Net defined benefit plans (972,917 ) 250,429 (722,488 ) Other comprehensive loss $ (2,177,821 ) $ 560,572 $ (1,617,249 ) Year Ended September 30, 2018: Interest rate swap: Unrealized gains $ 217,773 $ (62,807 ) $ 154,966 Transfer of realized gains to interest expense (24,053 ) 6,937 (17,116 ) Net interest rate swap 193,720 (55,870 ) 137,850 Defined benefit plans: Net gain arising during period $ 595,570 $ (171,775 ) $ 423,795 Amortization of actuarial gains (23,887 ) 6,890 (16,997 ) Net defined benefit plans 571,683 (164,885 ) 406,798 Other comprehensive income $ 765,403 $ (220,755 ) $ 544,648 Year Ended September 30, 2017: Interest rate swaps: Unrealized gains $ 116,843 $ (44,354 ) $ 72,489 Net interest rate swaps 116,843 (44,354 ) 72,489 Defined benefit plans: Net gain arising during period $ 1,715,505 $ (651,892 ) $ 1,063,613 Amortization of actuarial losses 256,234 (97,369 ) 158,865 Net defined benefit plans 1,971,739 (749,261 ) 1,222,478 Other comprehensive income $ 2,088,582 $ (793,615 ) $ 1,294,967 The amortization of actuarial gains or losses are included as a component of net periodic pension and postretirement benefit costs under other income (expense), net. Composition of AOCI: Interest Rate Swaps Defined Benefit Plans Accumulated Other Comprehensive Income (Loss) Balance September 30, 2016 $ — $ (2,497,231 ) $ (2,497,231 ) Other comprehensive income (loss) 72,489 1,222,478 1,294,967 Balance September 30, 2017 72,489 (1,274,753 ) (1,202,264 ) Other comprehensive income (loss) 137,850 406,798 544,648 Reclassification adjustment for the effect of change in tax law 20,285 (234,337 ) (214,052 ) Balance September 30, 2018 230,624 (1,102,292 ) (871,668 ) Other comprehensive income (loss) (894,761 ) (722,488 ) (1,617,249 ) Balance September 30, 2019 $ (664,137 ) $ (1,824,780 ) $ (2,488,917 ) The reclassification related to the interest rate swap was charged to regulatory liability to offset the adjustment made when revaluing the deferred tax liability of the interest rate swap for the reduction in corporate income tax rates. See recently adopted accounting standards for more information on the reclassification from AOCI. Financial Statement Reclassifications Reclassifications to certain line items of the prior years' consolidated balance sheet and consolidated income statements were made to place them on a comparable basis with the current year. The changes to the consolidated income statements are associated with the adoption of ASU 2017-07, Compensation - Retirement Benefits, which changed the income statement location of the components of net periodic benefit costs other than service cost. The changes to the consolidated income statements for the years ended September 30, 2018 and 2017 are reflected below and discussed in more detail under the recently adopted accounting standards section. Year Ended September 30, 2018 As Previously Reported Effect of Change As Adjusted Operation and maintenance 12,348,890 122,538 12,471,428 Total operating expenses 53,941,691 122,538 54,064,229 Operating income 11,593,045 (122,538 ) 11,470,507 Other income (expense), net 122,330 122,538 244,868 Income before income taxes 10,192,341 — 10,192,341 Year Ended September 30, 2017 As Previously Reported Effect of Change As Adjusted Operation and maintenance 13,100,041 (526,433 ) 12,573,608 Total operating expenses 50,630,561 (526,433 ) 50,104,128 Operating income 11,666,309 526,433 12,192,742 Other income (expense), net (132,446 ) (526,433 ) (658,879 ) Income before income taxes 10,038,255 — 10,038,255 The changes to the balance sheet relate to aggregating regulatory assets and liabilities that had been previously included in other financial statement line items into their own financial statement line item. This change allows for better presentation in the financial statements. September 30, 2018 As Previously Reported Effect of Change As Adjusted Current Assets: Accounts receivable, net 3,913,830 (169,602 ) 3,744,228 Under-recovery of gas cost 922,898 (922,898 ) — Other 980,972 (293,000 ) 687,972 Regulatory assets — 1,385,500 1,385,500 Current Liabilities: Accrued expenses 3,750,466 (670,034 ) 3,080,432 Rate refund 1,320,167 (1,320,167 ) — Regulatory liabilities — 1,990,201 1,990,201 Recently Adopted Accounting Standards In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. Subsequently issued ASUs provided additional guidance to assist in the implementation of the new revenue standard. The Company adopted ASU 2014-09 and all amendments beginning in fiscal 2019. Consistent with the modified retrospective adoption method, prior reporting period results remain unchanged and reported in accordance with ASC 605. As it relates to the Company’s contracts to deliver natural gas to customers, the guidance in ASC 606 is consistent with the guidance in ASC 605; therefore, the modified retrospective approach resulted in no cumulative catch-up to retained earnings. Furthermore, there was no significant impact to revenues recognized and no significant changes to the Company’s related business processes, systems or internal controls over financial reporting because of the new guidance. See Note 2 for additional information. In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits . The primary objective of this guidance is to improve the financial statement presentation of net periodic pension and postretirement benefit costs; however, it also changes which cost components are eligible for capitalization. The amendments in the ASU require that an employer report the service cost component in the same line item or items as other compensation costs arising from services rendered by the employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and, if a subtotal for income from operations is presented, outside of income from operations. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company and from allowed regulatory accounting. The Company adopted the new guidance in fiscal 2019 and has reclassified the other components of net periodic benefit costs for prior years to other income (deductions) in the non-operating section of the consolidated income statements. The impact to the income statement for the adoption of this ASU is reflected under the Financial Statement Reclassifications section above. The Company also implemented the change in capitalization costs on a prospective basis. This change did not have a significant impact on the Company's consolidated financial statements. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities . The ASU enhances the reporting model for financial instruments to provide users of the financial statements with more useful information through several provisions, including the following: (1) requires equity investments, excluding investments accounted for under the equity method, be measured at fair value with changes in fair value recognized in net income, (2) simplifies the impairment assessment of equity investments without readily determinable fair values, (3) eliminates the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet, (4) requires entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, and (5) requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. The Company adopted the ASU in fiscal 2019. The new guidance did not have a material effect on its financial position, results of operations or cash flows. See Note 13 for more information on fair value. In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The ASU provides the option to reclassify stranded tax effects within AOCI to retained earnings in each period in which the effects of the change in the U.S. federal corporate income tax rate, per the TCJA, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management completed its evaluation and adopted the new guidance in the fourth quarter of fiscal 2018. As a result, the Company reclassified $234,337 in stranded tax expense out of AOCI to retained earnings related to pension and postretirement plans for the unregulated operations of Resources. In addition, the Company also reclassified $20,285 out of AOCI to the regulatory liability for the stranded tax expense related to the interest rate swap. See the Other Comprehensive Income section above and Note 3 below for more information. Recently Issued Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases. The ASU leaves the accounting for leases mostly unchanged for lessors, with the exception of targeted improvements for consistency; however, the new guidance requires lessees to recognize assets and liabilities for leases with terms of more than 12 months. The ASU also revises the definition of a lease as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. Consistent with current GAAP, the presentation and cash flows arising from a lease by a lessee will primarily depend on its classification as a finance or operating lease. In contrast, the new ASU requires both types of leases to be recognized on the balance sheet. I |
