10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarterly Period Ended March 31, 2019

Commission File Number 000-26591

RGC Resources, Inc.(Exact name of Registrant as Specified in its Charter)

VIRGINIA	54-1909697
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
519 Kimball Ave., N.E., Roanoke, VA	24016
(Address of Principal Executive Offices)	(Zip Code)

(540) 777-4427

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

____________________________________________________ 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

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.

Large accelerated filer	¨	Accelerated filer	ý
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	ý
		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  ý

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

Class	Outstanding at April 30, 2019
Common Stock, $5 Par Value	8,045,409

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	Unaudited
	March 31, 2019			September 30, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,967,563		$	247,411
Accounts receivable (less allowance for uncollectibles of $377,372 and $103,573, respectively)	11,872,956			3,913,830
Materials and supplies	960,565			913,889
Gas in storage	1,904,277			7,627,196
Prepaid income taxes	—			837,683
Under-recovery of gas costs	—			922,898
Interest rate swap	54,786			100,723
Other	1,662,857			980,972
Total current assets	18,423,004			15,544,602
UTILITY PROPERTY:
In service	229,700,422			224,854,320
Accumulated depreciation and amortization	(65,761,219		)	(63,099,306		)
In service, net	163,939,203			161,755,014
Construction work in progress	9,997,035			4,208,614
Utility plant, net	173,936,238			165,963,628
OTHER ASSETS:
Regulatory assets	8,769,840			8,862,147
Investment in unconsolidated affiliates	36,276,548			28,507,146
Interest rate swap	86,745			209,840
Other	515,632			472,743
Total other assets	45,648,765			38,051,876
TOTAL ASSETS	$	238,008,007		$	219,560,106

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	Unaudited
	March 31, 2019			September 30, 2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Dividends payable	$	1,334,680		$	1,242,753
Accounts payable	5,326,625			5,211,032
Capital contributions payable	3,346,681			10,142,766
Customer credit balances	459,840			1,003,622
Income taxes payable	521,764			—
Customer deposits	1,560,403			1,421,043
Accrued expenses	3,372,121			3,750,466
Over-recovery of gas costs	2,674,341			—
Regulatory liability	2,785,993			1,320,167
Total current liabilities	21,382,448			24,091,849
LONG-TERM DEBT:
Notes payable	87,222,200			63,243,200
Line-of-credit	—			7,361,017
Less unamortized debt issuance costs	(317,235		)	(282,281		)
Long-term debt net of unamortized debt issuance costs	86,904,965			70,321,936
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	6,567,409			6,417,948
Regulatory cost of retirement obligations	11,770,061			11,163,981
Benefit plan liabilities	3,742,555			3,947,967
Deferred income taxes	11,953,317			12,585,577
Regulatory liability - deferred income taxes	10,712,735			11,447,736
Total deferred credits and other liabilities	44,746,077			45,563,209
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 8,043,272 and 7,994,615, respectively	40,216,360			39,973,075
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	13,868,387			13,043,656
Retained earnings	31,890,788			27,438,049
Accumulated other comprehensive loss	(1,001,018		)	(871,668		)
Total stockholders’ equity	84,974,517			79,583,112
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	238,008,007		$	219,560,106

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2019 AND 2018

UNAUDITED

	Three Months Ended March 31,				Six Months Ended March 31,
	2019		2018		2019		2018
OPERATING REVENUES:
Gas utility	$	25,058,749	$	24,608,576	$	46,095,330	$	43,128,570
Non utility	216,210		309,397		396,376		545,454
Total operating revenues	25,274,959		24,917,973		46,491,706		43,674,024
OPERATING EXPENSES:
Cost of gas - utility	12,771,338		13,743,277		24,677,797		23,304,683
Cost of sales - non utility	124,243		167,987		234,946		289,197
Operations and maintenance	3,714,084		3,488,889		7,236,083		6,716,633
General taxes	556,336		506,857		1,064,225		973,179
Depreciation and amortization	1,905,475		1,734,878		3,810,950		3,469,756
Total operating expenses	19,071,476		19,641,888		37,024,001		34,753,448
OPERATING INCOME	6,203,483		5,276,085		9,467,705		8,920,576
Equity in earnings of unconsolidated affiliate	698,175		191,513		1,261,224		340,324
Other income (expense), net	121,709		41,948		247,595		56,449
Interest expense	892,649		633,186		1,709,431		1,245,831
INCOME BEFORE INCOME TAXES	6,130,718		4,876,360		9,267,093		8,071,518
INCOME TAX EXPENSE	1,460,628		1,410,431		2,162,841		2,546,127
NET INCOME	$	4,670,090	$	3,465,929	$	7,104,252	$	5,525,391
BASIC EARNINGS PER COMMON SHARE	$	0.58	$	0.47	$	0.89	$	0.76
DILUTED EARNINGS PER COMMON SHARE	$	0.58	$	0.47	$	0.88	$	0.75
DIVIDENDS DECLARED PER COMMON SHARE	$	0.1650	$	0.1550	$	0.3300	$	0.3100

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2019 AND 2018

UNAUDITED

	Three Months Ended March 31,						Six Months Ended March 31,
	2019			2018			2019			2018
NET INCOME	$	4,670,090		$	3,465,929		$	7,104,252		$	5,525,391
Other comprehensive income (loss), net of tax:
Interest rate swap	(44,121		)	61,773			(125,524		)	106,418
Defined benefit plans	(1,913		)	(4,249		)	(3,826		)	(8,498		)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	(46,034		)	57,524			(129,350		)	97,920
COMPREHENSIVE INCOME	$	4,624,056		$	3,523,453		$	6,974,902		$	5,623,311

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE THREE-MONTH AND SIX-MONTH PERIODS ENDED MARCH 31, 2019 AND 2018

UNAUDITED

	Six Months Ended March 31, 2019
	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity
Balance - September 30, 2018	$	39,973,075	$	13,043,656	$	27,438,049		$	(871,668	)	$	79,583,112
Net Income	—		—		2,434,162			—			2,434,162
Other comprehensive loss	—		—		—			(83,316		)	(83,316		)
Cash dividends declared ($0.165 per share)	—		—		(1,322,335		)	—			(1,322,335		)
Issuance of common stock (17,035 shares)	85,175		262,942		—			—			348,117
Balance - December 31, 2018	$	40,058,250	$	13,306,598	$	28,549,876		$	(954,984	)	$	80,959,740
Net Income	—		—		4,670,090			—			4,670,090
Other comprehensive loss	—		—		—			(46,034		)	(46,034		)
Cash dividends declared ($0.165 per share)	—		—		(1,329,178		)	—			(1,329,178		)
Issuance of common stock (31,622 shares)	158,110		561,789		—			—			719,899
Balance - March 31, 2019	$	40,216,360	$	13,868,387	$	31,890,788		$	(1,001,018	)	$	84,974,517
	Six Months Ended March 31, 2018
	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity
Balance - September 30, 2017	$	36,204,230	$	292,485	$	24,746,021		$	(1,202,264	)	$	60,040,472
Net Income	—		—		2,059,462			—			2,059,462
Other comprehensive income	—		—		—			40,396			40,396
Cash dividends declared ($0.155 per share)	—		—		(1,125,804		)	—			(1,125,804		)
Issuance of common stock (10,168 shares)	50,840		235,669		—			—			286,509
Balance - December 31, 2017	$	36,255,070	$	528,154	$	25,679,679		$	(1,161,868	)	$	61,301,035
Net income	—		—		3,465,929			—			3,465,929
Other comprehensive income	—		—		—			57,524			57,524
Cash dividends declared ($0.155 per share)	—		—		(1,236,407		)	—			(1,236,407		)
Issuance of common stock (724,378 shares)	3,621,890		12,089,255		—			—			15,711,145
Balance - March 31, 2018	$	39,876,960	$	12,617,409	$	27,909,201		$	(1,104,344	)	$	79,299,226

See notes to condensed consolidated financial statements.

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE SIX-MONTH PERIODS ENDED MARCH 31, 2019 AND 2018

UNAUDITED

	Six Months Ended March 31,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,104,252		$	5,525,391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	3,880,945			3,531,558
Cost of retirement of utility plant, net	(123,237		)	(126,686		)
Equity in earnings of unconsolidated affiliate	(1,261,224		)	(340,324		)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately	1,332,387			2,058,589
Net cash provided by operating activities	10,933,123			10,648,528
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(10,975,996		)	(10,065,690		)
Investment in unconsolidated affiliate	(13,304,263		)	(3,804,844		)
Proceeds from disposal of equipment	1,219			18,541
Net cash used in investing activities	(24,279,040		)	(13,851,993		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	23,979,000			11,951,000
Borrowings under line-of-credit agreement	23,308,642			19,533,761
Repayments under line-of-credit agreement	(30,669,659		)	(37,325,521		)
Debt issuance costs	(60,343		)	—
Proceeds from issuance of stock	1,068,016			15,997,654
Cash dividends paid	(2,559,587		)	(2,176,495		)
Net cash provided by financing activities	15,066,069			7,980,399
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,720,152			4,776,934
BEGINNING CASH AND CASH EQUIVALENTS	247,411			69,640
ENDING CASH AND CASH EQUIVALENTS	$	1,967,563		$	4,846,574
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	1,549,778		$	1,014,517
Income taxes paid	1,623,000			635,000

See notes to condensed consolidated financial statements.

6

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. Basis of Presentation

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.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly Resources' financial position as of March 31, 2019 and the results of its operations, cash flows, comprehensive income and changes in stockholders' equity for the three and six months ended March 31, 2019 and 2018. The results of operations for the three and six months ended March 31, 2019 are not indicative of the results to be expected for the fiscal year ending September 30, 2019 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The unaudited condensed consolidated interim financial statements and condensed notes are presented as permitted under the rules and regulations of the Securities and Exchange Commission. Pursuant to those rules, certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures are adequate to make the information not misleading. Therefore, the condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K for the year ended September 30, 2018. The September 30, 2018 balance sheet was included in the Company’s audited financial statements included in Form 10-K.

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.

The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements in Form 10-K for the year ended September 30, 2018. Newly adopted and newly issued accounting standards are discussed below.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This reclassification does not change net income and makes the Company's income statement presentation consistent with industry peers.

Recently Issued or 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 standard is effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period.

The Company adopted ASU 2014-09 and all amendments beginning in the quarter ended December 31, 2018. 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

7

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 further information.

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 beginning with the quarter ended December 31, 2018. The new guidance did not have a material effect on the Company's financial position, results of operations or cash flows.

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. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. 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. In January 2018, the FASB issued ASU 2018-01, which provides a practical expedient that allows entities the option of not evaluating existing land easements under the new lease standard for those easements that were entered into prior to adoption. New or modified land easements will require evaluation on a prospective basis. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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. The Company adopted the new guidance effective October 1, 2018. As a result, the Company now presents the other components of net periodic benefit costs outside of operations under the category of "other income (expense), net" in the condensed consolidated income statement. As the new guidance related to the expense classification was implemented on a retrospective basis, adjustments were made to the prior period financial statements as follow:

8

	Three Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	3,458,256		$	30,633		$	3,488,889
Total operating expenses	19,611,255			30,633			19,641,888
Operating income	5,306,718			(30,633		)	5,276,085
Other income (expense), net	11,315			30,633			41,948
Income before income taxes	$	4,876,360		$	—		$	4,876,360
	Six Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	6,655,367		$	61,266		$	6,716,633
Total operating expenses	34,692,182			61,266			34,753,448
Operating income	8,981,842			(61,266		)	8,920,576
Other income (expense), net	(4,817		)	61,266			56,449
Income before income taxes	$	8,071,518		$	—		$	8,071,518

In addition, the ASU allows only the service cost component of net periodic benefit cost to be eligible for capitalization when applicable. Previously, the Company included all components of net periodic benefit costs for capitalization. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company adopted the capitalization change prospectively on October 1, 2018. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits are not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. The adoption of this new guidance does not have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. 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 has not completed its evaluation of the new guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

9

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.

2. Revenue

The Company assesses new contracts and identifies related performance obligations for promises to transfer distinct goods or services to the customer. Revenue is recognized when performance obligations have been satisfied. In the case of Roanoke Gas, the Company contracts with its customers for the sale and/or delivery of natural gas.

The following tables summarize revenue by customer, product and income statement classification:

	Three months ended March 31, 2019								Three months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	15,397,504		$	—	$	15,397,504		$	15,479,644		$	—	$	15,479,644
Commercial	8,357,598			—		8,357,598			8,504,212			—		8,504,212
Industrial and Transportation	1,249,316			—		1,249,316			1,137,874			—		1,137,874
Revenue reductions (TCJA) (1)	—			—		—			(358,901		)	—		(358,901		)
Other	108,418			216,210		324,628			148,505			309,397		457,902
Total contracts with customers	25,112,836			216,210		25,329,046			24,911,334			309,397		25,220,731
Alternative Revenue Programs	(54,087		)	—		(54,087		)	(302,758		)	—		(302,758		)
Total operating revenues	$	25,058,749		$	216,210	$	25,274,959		$	24,608,576		$	309,397	$	24,917,973
	Six months ended March 31, 2019								Six months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	28,410,332		$	—	$	28,410,332		$	26,700,554		$	—	$	26,700,554
Commercial	15,700,155			—		15,700,155			14,820,511			—		14,820,511
Industrial and Transportation	2,475,364			—		2,475,364			2,265,677			—		2,265,677
Revenue reductions (TCJA) (1)	(523,881		)	—		(523,881		)	(821,343		)	—		(821,343		)
Other	334,908			396,376		731,284			393,770			545,454		939,224
Total contracts with customers	46,396,878			396,376		46,793,254			43,359,169			545,454		43,904,623
Alternative Revenue Programs	(301,548		)	—		(301,548		)	(230,599		)	—		(230,599		)
Total operating revenues	$	46,095,330		$	396,376	$	46,491,706		$	43,128,570		$	545,454	$	43,674,024
(1) Accrued refund associated with excess revenue collected in tariff rates associated with the reduction in federal income tax rates. See Note 4 for more information.

Gas utility revenues

Substantially all of Roanoke Gas’ revenues are derived from rates authorized by the Virginia State Corporation Commission ("SCC") as reflected in its tariffs. Based on its evaluation of ASC 606, the Company has concluded that these tariff-based revenues fall within the scope of ASC 606. Tariff rates represent the transaction price. Performance obligations created under these tariff-based sales include commodity (the cost of natural gas sold to customers) and delivery (transporting natural gas through the Company’s distribution system to customers). The sale and/or delivery of natural gas to customers result in the satisfaction of the Company’s performance obligation over time as natural gas is delivered.

10

All customers are billed each month based on consumption as measured by metered usage. Revenue is recognized as bills are issued for natural gas that has been delivered or transported to customers. In addition, the Company utilizes the practical expedient that allows an entity to recognize the invoiced amount as revenue, if that amount corresponds to the value received by the customer. Since customers are billed tariff rates, there is no variable consideration in transaction price.

Unbilled revenue is included in residential and commercial revenues above. Natural gas consumption is estimated for the period subsequent to the last billed date and up through the last day of the month. Estimated volumes and approved tariff rates are utilized to calculate unbilled revenue. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The Company obtains metered usage for industrial customers at the end of each month, thereby eliminating any unbilled consideration for these rate classes.

Other revenues

Other revenues primarily consist of miscellaneous fees and charges and utility-related revenues not directly billed to utility customers, as well as billings for non utility activities. Non utility (unregulated) activities provided by the Company include contract paving and other similar services. Regarding these activities, the customer is invoiced monthly based on services provided. The Company utilizes the practical expedient allowing revenue to be recognized based on invoiced amounts. The transaction price is based on a contractually predetermined rate schedule; therefore, the transaction price represents total value to the customer and no variable price consideration exists.

Alternative Revenue Program (ARP) revenues

ARPs, which fall outside the scope of ASC 606, are SCC approved mechanisms that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets. The Company's ARPs include its Weather Normalization Adjustment (WNA), which adjusts revenues for the effects of weather temperature variations from the 30-year average, and the SAVE ("Steps to Advance Virginia's Energy") Plan over/under collection mechanism, which adjusts revenues for the differences between SAVE Plan revenues billed to customers in the current tariff rates and the revenue earned, as calculated based on the timing and extent of infrastructure replacement completed during the period. These amounts are ultimately collected from, or returned to, customers through future changes to tariff rates.

Customer Accounts Receivable

Accounts receivable, as reflected in the Condensed Consolidated Balance Sheets, includes both billed and unbilled customer revenues, as well as amounts that are not related to customers. The balances of customer receivables are provided below:

	Assets (current)				Liabilities (current)
	Trade accounts receivable (1)		Unbilled revenue (1)		Customer credit balances			Customer deposits
Balance at September 30, 2018	$	2,675,611	$	913,087	$	1,003,622		$	1,421,043
Balance at March 31, 2019	9,001,334		2,796,670		459,840			1,560,403
Increase (decrease)	$	6,325,723	$	1,883,583	$	(543,782	)	$	139,360
(1) Included in "Accounts receivable, net" in the condensed consolidated balance sheet. Amounts shown net of reserve for bad debts.

The Company had no significant contract assets or liabilities during the period. Furthermore, the Company did not incur any significant costs to obtain contracts.

3. Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act, ("TCJA") became law. The TCJA's most significant impact was the reduction of the maximum corporate federal income tax rate from 35% to 21% beginning January 1, 2018. As the Company is a fiscal year taxpayer, it had a blended rate of 24.3% in fiscal 2018 and fully transitioned to the 21%, rate in fiscal 2019.

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Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be revalued to reflect the reduction in the federal tax rate. For unregulated entities, the revaluation of excess deferred income taxes are flowed through income tax expense in the period of change. For rate regulated entities such as Roanoke Gas, these excess deferred taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. As a result, these net excess deferred taxes must be returned to customers. The Company began reflecting the refund of these excess deferred taxes in late fiscal 2018. As the refund should have no effect on the income of the Company, the income statement reflects both a reduction in revenues and a corresponding reduction in income taxes associated with the flow back of these net excess deferred taxes. The result is a lowering of the effective tax rate for the Company.

A reconciliation of income tax expense from applying the federal statutory rates in effect for each period to total income tax expense is presented below:

	Three Months Ended March 31,						Six Months Ended March 31,
	2019			2018			2019			2018
Income before income taxes	$	6,130,718		$	4,876,360		$	9,267,093		$	8,071,518
Corporate federal tax rate	21.00		%	24.30		%	21.00		%	24.30		%
Income tax expense computed at the federal statutory rate	$	1,287,451		$	1,184,955		$	1,946,090		$	1,961,379
State income taxes, net of federal tax benefit	290,481			222,127			441,070			368,214
Net amortization of excess deferred taxes on regulated operations	(86,208		)	—			(172,417		)	—
Revaluation of unregulated deferred taxes	—			—			—			206,830
Other, net	(31,096		)	3,349			(51,902		)	9,704
Total income tax expense	$	1,460,628		$	1,410,431		$	2,162,841		$	2,546,127
Effective tax rate	23.8		%	28.9		%	23.3		%	31.5		%

4. Rates and Regulatory Matters

The 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.

As referenced in Note 3, the TCJA reduced the federal corporate tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows directly to income tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the adjustment to the net deferred tax liabilities of Roanoke Gas, to the extent such net deferred tax liabilities are attributable to rate base or cost of service for customers, are refundable to customers. Roanoke Gas began accounting for the refund of these excess deferred taxes in fiscal 2018 along with reflecting a corresponding reduction in income tax expense. As of March 31, 2019, Roanoke Gas had approximately $11,200,000 remaining in both the current and non-current portions of the net regulatory liability related to these excess deferred income taxes, most of which will be refunded over a 28 year period per IRS normalization requirements. The provision for excess deferred taxes included in regulatory liabilities are subject to SCC review and adjustment as part of their audit of the general rate application.

The Company has transitioned to a corporate federal income tax rate of 21% and a combined 25.74% state and federal tax rate in fiscal 2019. In January 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, currently included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. For the

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RGC RESOURCES, INC. AND SUBSIDIARIES

six-month periods ending March 31, 2019 and 2018, the Company had recorded a reduction to revenue of $523,881 and $821,343, respectively, reflecting the estimated excess revenue collected from customers. Effective with January 2019 customer billings, the Company began refunding the excess revenues to customers. The estimated total refund of these excess revenues is subject to final review and adjustment by the SCC as part of their review of the general rate application.

On October 10, 2018, Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates of $10.5 million. This application incorporates into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs and approximately $4.7 million in SAVE plan revenues that were previously billed through the SAVE rider. The new non-gas base rates were placed in effect for service rendered on or after January 1, 2019, subject to refund pending audit and final order by the SCC. SCC staff is currently auditing the rate application and their report is not due until later in the Company's fiscal third quarter. The Company has recorded a provision for refund, including interest associated with customer billings, under the new rates. As the SCC audit is still in progress, the Company based its estimated refund on the history of the percentage of additional revenues realized from past rate applications. The amount of the refund is an estimate, and the final order could result in lower or higher revenues than currently reflected in the financial statements. The Company will refine its estimates as more information becomes available.

The current portion of the excess deferred income tax, the accrued refund for excess revenues due to tax rate change and the estimated refund related to the non-gas rates placed into effect on January 1, 2019 are included in the regulatory liabilities line in the Condensed Consolidated Balance Sheet.

The SCC requires regulated entities within the state to perform a depreciation study every 5 years. The Company completed its last depreciation study in June 2014 and is currently in the process of preparing the current depreciation study for filing in June 2019. The new depreciation rates are effective retroactive to October 1, 2018 and will be implemented once approved by the SCC. Any adjustment to depreciation expense as a result of the study is expected to be reflected in the results of the quarter ended September 30, 2019.

5. Other Investments

In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”).

The LLC was established to construct and operate the Mountain Valley Pipeline ("MVP" or "pipeline"), a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. When completed, the pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day. The pipeline has received Federal Energy Regulatory Commission ("FERC") approval and is under construction.

The current total project cost as estimated by the LLC managing partner is $4.6 billion. Midstream's estimated total cash contribution for its 1% equity interest in the LLC will be approximately $46 million provided through periodic capital contributions made throughout the term of the project. The Company is utilizing the equity method to account for the transactions and activity of the investment in MVP and is participating in the earnings in proportion to its level of investment.

In April 2018, the LLC announced the MVP Southgate project ("Southgate"), which is a 70 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in the project, which will be accounted for under the cost method. Total estimated project cost is between $350 and $500 million, of which Midstream's portion estimated to be between $1.8 to $2.5 million.

On a quarterly basis, the LLC issues a capital call notice, which specifies the capital contributions for MVP and Southgate to be paid over the subsequent 3 months. As of March 31, 2019, the Company had $3,346,681 remaining to be paid under the most recent notice. The capital contribution payable has been reflected on the Company's Balance Sheet as of March 31, 2019, with a corresponding increase to "investment in unconsolidated affiliates". Related to capital contributions payable, there was a $6,796,085 non-cash decrease in the "investment in unconsolidated affiliates" during the six months ended March 31, 2019. Funding for Midstream's investments in the LLC for both the MVP and Southgate projects are being provided through two unsecured promissory notes, each with a 5-year term as discussed further in Note 7.

The financial statement locations of the investment in the LLC are as follows:

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RGC RESOURCES, INC. AND SUBSIDIARIES

Balance Sheet Location of Other Investments:	March 31, 2019		September 30, 2018
Other Assets:
Investment in MVP	$	36,065,841	$	28,387,031
Investment in Southgate	210,707		120,115
Investment in unconsolidated affiliates	$	36,276,548	$	28,507,146

Current Liabilities:
MVP	$	3,275,544	$	10,022,652
Southgate	71,137		120,114
Capital contributions payable	$	3,346,681	$	10,142,766

	Three Months Ended				Six Months Ended
Income Statement Location of Other Investments:	March 31, 2019		March 31, 2018		March 31, 2019		March 31, 2018
Equity in earnings of unconsolidated affiliate	$	698,175	$	191,513	$	1,261,224	$	340,324

6. Derivatives and Hedging

The Company’s risk management 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 risk management policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company seeks to hedge include the price of natural gas and the cost of borrowed funds.

The Company has one interest rate swap associated with its $7,000,000 term note as discussed in Note 7. Effective November 1, 2017, the swap agreement converted the floating rate note based on LIBOR into fixed-rate debt with a 2.30% effective interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swap was deemed ineffective during the periods presented.

The table below reflects the fair values of the derivative instrument and its corresponding classification in the condensed consolidated balance sheet:

	March 31, 2019	September 30, 2018
Derivative designated as hedging instrument:
Current assets:
Interest rate swap	$54,786	$100,723
Other assets:
Interest rate swap	$86,745	$209,840
Total derivatives designed as hedging instruments	$141,531	$310,563

The table in Note 8 reflects the effect on income and other comprehensive income of the Company's cash flow hedge.

7. Long-Term Debt

On January 2, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10 million. These notes, issued on March 28, 2019, will mature 12-years from the date of issue and have a fixed interest rate of 4.41%. Proceeds from these notes were used to refinance a portion of Roanoke Gas' debt under the line-of-credit.

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement. This agreement replaced the prior line-of-credit agreement scheduled to expire March 31, 2020. The new agreement is for a two-year term expiring

14

March 31, 2021 with a maximum borrowing limit of $30,000,000. Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits associated with the seasonal borrowing demands of the Company. The Company's total available borrowing limits during the term of the agreement range from $3,000,000 to $30,000,000.

On February 19, 2019, Midstream entered into an agreement with the lending institutions to amend its existing credit agreement and related notes. The amendment increased total borrowing limits to $50 million through the date of maturity to meet the projected funding requirements for completion of the MVP. With the exception of the increase in borrowing limits, all remaining terms under the notes remain unchanged including the variable-interest rate based on 30-day LIBOR plus 135 basis points.

Roanoke Gas also has other unsecured notes at varying fixed interest rates as well as a variable-rate note with interest based on 30-day LIBOR plus 90 basis points. The variable rate note is hedged by a swap agreement, which converts the debt into a fixed-rate instrument with an annual interest rate of 2.30%.

All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that limit consolidated long-term indebtedness to not more than 65% of total capitalization. All of the debt agreements, except for the line-of-credit, provide for priority indebtedness to not exceed 15% of consolidated total assets.

Long-term debt consists of the following:

	March 31, 2019				September 30, 2018
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Roanoke Gas Company:
Unsecured senior notes payable, at 4.26% due on September 18, 2034	$	30,500,000	$	149,638	$	30,500,000	$	154,465
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		8,615		7,000,000		10,283
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		40,936		8,000,000		43,343
Unsecured term notes payable, at 4.41% due on March 28, 2031	10,000,000		33,521		—		—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35%, due December 29, 2020	31,722,200		84,525		17,743,200		74,190
Total notes payable	$	87,222,200	$	317,235	$	63,243,200	$	282,281
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2021	$	—	$	—	$	7,361,017	$	—
Total long-term debt	$	87,222,200	$	317,235	$	70,604,217	$	282,281

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RGC RESOURCES, INC. AND SUBSIDIARIES

8. Other Comprehensive Income

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

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(40,059	)	$	10,311		$	(29,748	)
Transfer of realized gains to interest expense	(19,355		)	4,982			(14,373		)
Net interest rate swap	(59,414		)	15,293			(44,121		)
Defined benefit plans:
Amortization of actuarial gains	(2,576		)	663			(1,913		)
Other comprehensive loss	$	(61,990	)	$	15,956		$	(46,034	)
Three Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	90,363		$	(26,061	)	$	64,302
Transfer of realized gains to interest expense	(3,554		)	1,025			(2,529		)
Net interest rate swap	86,809			(25,036		)	61,773
Defined benefit plans:
Amortization of actuarial gains	(5,971		)	1,722			(4,249		)
Other comprehensive income	$	80,838		$	(23,314	)	$	57,524

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Six Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(134,015	)	$	34,495		$	(99,520	)
Transfer of realized gains to interest expense	(35,017		)	9,013			(26,004		)
Net interest rate swap	(169,032		)	43,508			(125,524		)
Defined benefit plans:
Amortization of actuarial gains	(5,152		)	1,326			(3,826		)
Other comprehensive loss	$	(174,184	)	$	44,834		$	(129,350	)
Six Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	151,944		$	(43,821	)	$	108,123
Transfer of realized gains to interest expense	(2,396		)	691			(1,705		)
Net interest rate swap	149,548			(43,130		)	106,418
Defined benefit plans:
Amortization of actuarial gains	(11,942		)	3,444			(8,498		)
Other comprehensive income	$	137,606		$	(39,686	)	$	97,920

The amortization of actuarial gains and losses is included as a component of net periodic pension and postretirement benefit costs under other income (expense), net.

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RGC RESOURCES, INC. AND SUBSIDIARIES

Reconciliation of Other Accumulated Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2018	$	(871,668	)
Other comprehensive loss	(129,350		)
Balance at March 31, 2019	$	(1,001,018	)

9. Commitments and Contingencies

Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its service area. The current franchise agreements expire December 31, 2035. The Company's certificates of public convenience and necessity are exclusive and are intended for perpetual duration. 

Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company utilizes an asset manager to assist in optimizing the use of its transportation, storage rights and gas supply in order to provide a secure and reliable source of natural gas to its customers. The Company also has storage and pipeline capacity contracts to store and deliver natural gas to the Company’s distribution system. Roanoke Gas is currently served directly by two primary pipelines. These two pipelines deliver all of the natural gas supplied to the Company’s distribution system. Depending on 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's ability to deliver natural gas to its customers and its results of operations. The MVP will provide Roanoke Gas with access to an additional delivery source to its distribution system, increasing system reliability and the Company's ability to meet future demands for natural gas.

10. Earnings Per Share

Basic earnings per common share for the three months and six months ended March 31, 2019 and 2018 were calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share were calculated by dividing net income by the weighted average common shares outstanding during the period plus potential dilutive common shares. A reconciliation of basic and diluted earnings per share is presented below:

	Three Months Ended March 31,				Six Months Ended March 31,
	2019		2018		2019		2018
Net Income	$	4,670,090	$	3,465,929	$	7,104,252	$	5,525,391
Weighted average common shares	8,032,218		7,371,694		8,017,820		7,309,215
Effect of dilutive securities:
Options to purchase common stock	40,931		41,657		44,600		45,018
Diluted average common shares	8,073,149		7,413,351		8,062,420		7,354,233
Earnings Per Share of Common Stock:
Basic	$	0.58	$	0.47	$	0.89	$	0.76
Diluted	$	0.58	$	0.47	$	0.88	$	0.75

11. Employee Benefit Plans

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 hired before January 1, 2017 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 is detailed as follows:

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of net periodic pension cost:
Service cost	$	134,317		$	166,309		$	268,634		$	332,618
Interest cost	291,682			272,045			583,364			544,090
Expected return on plan assets	(387,359		)	(465,710		)	(774,718		)	(931,420		)
Recognized loss	39,650			87,758			79,300			175,516
Net periodic pension cost	$	78,290		$	60,402		$	156,580		$	120,804

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of postretirement benefit cost:
Service cost	$	33,221		$	41,805		$	66,442		$	83,610
Interest cost	162,236			160,151			324,472			320,302
Expected return on plan assets	(136,805		)	(155,845		)	(273,610		)	(311,690		)
Recognized loss	30,951			70,967			61,902			141,934
Net postretirement benefit cost	$	89,603		$	117,078		$	179,206		$	234,156

The components of net periodic benefit cost, other than the service cost component, are included in the line item "other income (expense), net" in the condensed consolidated income statement as prescribed under ASU 2017-07 and discussed in Note 1. Service cost is included in the "operations and maintenance" line.

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.

	Fiscal Year-to-Date Contributions		Remaining Fiscal Year Contributions
Defined benefit pension plan	$	400,000	$	400,000
Postretirement medical plan	—		300,000
Total	$	400,000	$	700,000

12. Fair Value Measurements

FASB ASC No. 820, Fair Value Measurements and Disclosures, established a fair value hierarchy that prioritizes each input to the valuation method used to measure fair value of financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis into one of the following three 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 for the asset or liability at the measurement date.

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RGC RESOURCES, INC. AND SUBSIDIARIES

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 following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as required by existing guidance and the fair value measurements by level within the fair value hierarchy as of March 31, 2019 and September 30, 2018:

			Fair Value Measurements - March 31, 2019
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	141,531	$	—	$	141,531	$	—
Total	$	141,531	$	—	$	141,531	$	—
Liabilities:
Natural gas purchases	$	430,759	$	—	$	430,759	$	—
Total	$	430,759	$	—	$	430,759	$	—
			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

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.

Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on weighted average first of the month index prices corresponding to the month of the scheduled payment. At March 31, 2019 and September 30, 2018, the Company had recorded in accounts payable the estimated fair value of the liability valued at the corresponding first of month index prices for which the liability is expected to be settled.

The Company’s nonfinancial assets and liabilities measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows required to settle the obligation.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments. In addition, the carrying amount of the variable rate line-of-credit is a reasonable approximation of its fair value. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of March 31, 2019 and September 30, 2018:

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RGC RESOURCES, INC. AND SUBSIDIARIES

			Fair Value Measurements - March 31, 2019
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	87,222,200	$	—	$	—	$	88,286,143
Total	$	87,222,200	$	—	$	—	$	88,286,143
			Fair Value Measurements - September 30, 2018
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

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 spreads.

FASB ASC 825, Financial Instruments, requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. As of March 31, 2019 and September 30, 2018, no single customer accounted for more than 5% of the total accounts receivable balance. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants.

13. Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were issued. There were no items not otherwise disclosed above which would have materially impacted the Company’s condensed consolidated financial statements.

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

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 2018 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 and six-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2019. The total revenues and margins realized during the first six 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 61,700 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 invests in the Mountain Valley Pipeline ("MVP"), an interstate pipeline currently under construction, as a 1% participant through its RGC Midstream, LLC subsidiary ("Midstream") in addition to providing certain unregulated services through Roanoke Gas and its other subsidiaries. The unregulated operations of Roanoke 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 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.

The Company has completed the transition to the 21% federal statutory income tax rate as a result of the Tax Cuts and Jobs Act ("TCJA") that was signed into law in December 2017. Since the implementation of the new tax rates, the Company has recorded a provision for refund related to estimated excess revenues collected from customers under approved billing rates that were designed to recover the operating expenses and provide a rate of return based on a federal tax rate of 34%. Beginning January 1, 2019, Roanoke Gas incorporated the effect of the 21% federal tax rate with the implementation of the new non-gas base rates as filed in its current rate application and began refunding the excess revenues associated with the change in the tax rate over the subsequent 12-month period. The Company also provided an estimated refund related to the new non-gas rates that were placed into effect on January 1, 2019. Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.

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Over 98% of the Company’s annual revenues, excluding equity in earnings of MVP, 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's Energy Plan ("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 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.

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) 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 and six months ended March 31, 2019, the Company accrued $46,000 in additional revenues under the WNA model for weather that was less than 1% warmer than normal and approximately $111,000 reduction in revenues for weather that was more than 1% colder than normal, respectively. For the corresponding periods last year, the Company accrued approximately $161,000 and $124,000 reduction in revenues for weather that was 3% and 2% colder than normal. The current WNA year ended on March 31, 2019, and once the SCC approves the billing factors, the Company will apply the amount to customers' bills.

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 and six month periods ended March 31, 2019 declined by approximately 12% from the same periods last year due to a combination of lower average natural gas storage balances and a reduction in the weighted average cost of capital factor used in calculating these revenues.

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. The additional investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure projects on a prospective basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provides a return on rate base for the related additional capital investments until such time that a

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formal rate application is filed. As the Company has made significant 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 new non-gas rate application, the SAVE Plan program has been reset as the prior qualified infrastructure investments were included in the derivation of the non-gas rates placed into effect in January 2019, subject to refund. Accordingly, SAVE Plan revenues declined by $1,146,000 for the three-month period ended March 31, 2019 compared to the same period last year and by approximately $1,014,000 for the corresponding six-month periods.

The Company 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 Ended March 31, 2019:

Net income increased by $1,204,161 for the three months ended March 31, 2019, compared to the same period last year. Improved quarterly performance is attributable to implementation of a non-gas rate increase, customer growth, equity in earnings from the investment in Mountain Valley Pipeline and lower income tax expense.

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

	Three Months Ended March 31,
	2019		2018		Increase / (Decrease)			Percentage
Operating Revenues
Gas Utility	$	25,058,749	$	24,608,576	$	450,173		2	%
Non utility	216,210		309,397		(93,187		)	(30	)%
Total Operating Revenues	$	25,274,959	$	24,917,973	$	356,986		1	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	3,281,556		3,362,966		(81,410		)	(2	)%
Transportation and Interruptible	799,875		781,428		18,447			2	%
Total Delivered Volumes	4,081,431		4,144,394		(62,963		)	(2	)%
Heating Degree Days (Unofficial)	2,045		2,134		(89		)	(4	)%

Total operating revenues for the three months ended March 31, 2019, compared to the same period last year, increased primarily due to the implementation of higher non-gas rates partially offset by lower gas costs. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new rates incorporated revenues related to SAVE Plan activities through December 2018, as well as recovery of higher costs and non SAVE infrastructure additions since the last rate application. Total revenues have been reduced by an estimate for potential refunds, pending the completion of the audit by the SCC and the issuance of a final order on the rate application. The average commodity price of natural gas delivered during the current quarter was approximately 6% per decatherm lower than the same period last year. In addition, the prior year included a reserve of $358,901 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.

See the Regulatory and Tax Reform section below for more information regarding the new non-gas base rates, provision for refund and the excess revenues related to the reduction in the corporate federal income tax rate.

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	Three Months Ended March 31,
	2019		2018		Increase / (Decrease)			Percentage
Gas Utility Margin
Utility Revenues	$	25,058,749	$	24,608,576	$	450,173		2	%
Cost of Gas	12,771,338		13,743,277		(971,939		)	(7	)%
Gas Utility Margin	$	12,287,411	$	10,865,299	$	1,422,112		13	%

Regulated natural gas margins from utility operations (total utility revenues less utility cost of gas) increased from the same period last year primarily as a result of the implementation of higher non-gas base rates as filed under the rate application with the SCC. SAVE revenues declined by $1,145,504 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates effective January 1, 2019. The result is a net increase in customer base charges of $1,185,278 and volumetric margin net of WNA of $1,063,626. The customer base charge and volumetric margins also include an estimated provision for refund. As noted above, the prior year included a reserve of $358,901 related to excess revenues to be refunded to customers due to the reduction in the federal income tax rate. Both the reserve for excess revenues associated with the reduction in the federal income tax rate and the new non-gas rates are subject to adjustment as the SCC completes their audit and ultimately issues a final order.

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

	Three Months Ended March 31,
	2019		2018			Increase / (Decrease)
Customer Base Charge	$	4,331,767	$	3,146,489		$	1,185,278
Carrying Cost	92,932		106,162			(13,230		)
SAVE Plan	23,025		1,168,529			(1,145,504		)
Volumetric	7,777,889		6,921,210			856,679
WNA	46,412		(160,535		)	206,947
Other Gas Revenues	15,386		42,345			(26,959		)
Excess Revenue Refund	—		(358,901		)	358,901
Total	$	12,287,411	$	10,865,299		$	1,422,112

Operation and maintenance expenses increased by $225,195, or 6%, from the same period last year primarily related to increased compensation costs, contracted and professional services and amortization of regulatory assets partially offset by higher capitalized overheads Total compensation costs increased by $113,000 due to higher employment levels and wage increases over the prior year. Contracted and professional services increased by $99,000 related to operational support and general facility maintenance activities. The Company began amortizing certain regulatory assets that are currently being recovered in the new non-gas base rates. Total amortization expense for the quarter was $66,000 based on a proposed 5-year amortization period per the rate filing. Total capitalized overheads increased by $84,000 due to higher capital expenditures.

General taxes increased by $49,479, or 10%, 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. Increased compensation levels resulted in higher payroll taxes.

Depreciation expense increased by $170,597, or 10%, on a corresponding increase in utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $506,662, more than triple last year, due to the extent of pipeline construction activities in the Mountain Valley Pipeline project. The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). The level of construction activity resulted in a greater amount of AFUDC income. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.

Other income (expense), net increased by $79,761 primarily due to the implementation of a revenue sharing incentive mechanism in 2018 related to the gas supply asset management agreement. See the Regulatory and Tax Reform section below for more information on revenue sharing. Furthermore, the adoption of ASU 2017-07, Compensation - Retirement Benefits, as discussed in Note 1, resulted in the components of net periodic benefit costs other than service cost being presented outside of

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income from operations. As a result, the prior year amount has been adjusted retrospectively with the reclassification of a $30,633 net expense reduction from operations and maintenance to other income (expense) while the current period includes a net expense of less than $1,000 for these other net periodic benefit costs.

Interest expense increased by $259,463, or 41% due to a 35% increase in total average debt outstanding between quarters. The higher borrowing levels derived from the ongoing investment in MVP, financing expenditures in support of Roanoke Gas' capital budget and rising interest rates on the Company's variable-rate debt. Total borrowing under Midstream's credit facility increased by more than $21 million while the average interest rate increased 58 basis points. The Company's line-of-credit experienced a similar interest rate increase. As a result, the weighted-average effective interest rate on total Company debt increased from 3.77% in the second quarter of fiscal 2018 to 3.97% during the second quarter of fiscal 2019.

Income tax expense increased by $50,197 due to higher taxable income mostly offset by a reduction in the federal income tax rate and the amortization of excess deferred taxes on the regulated operations of Roanoke Gas. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019 with the combined state and federal rate declining from 28.84% to 25.74%. In fiscal 2018, Roanoke Gas revalued the net deferred tax liability of its regulated operations and recorded a regulatory liability, which is being amortized as a credit to tax expense over a 28 year period corresponding with a comparable reduction in revenues through reduced billings to customers. This results in no impact to net income as the reduction in income tax expense corresponds to a reduction in revenues. See Regulatory and Tax Reform section for more information.

Six Months Ended March 31, 2019:

Net income increased by $1,578,861 for the six months ended March 31, 2019, compared to the same period last year due to the implementation of a non-gas rate increase, equity in earnings from the investment in Mountain Valley Pipeline and lower income tax rates.

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

	Six Months Ended March 31,
	2019		2018		Increase / (Decrease)			Percentage
Operating Revenues
Gas Utility	$	46,095,330	$	43,128,570	$	2,966,760		7	%
Non utility	396,376		545,454		(149,078		)	(27	)%
Total Operating Revenues	$	46,491,706	$	43,674,024	$	2,817,682		6	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	5,647,630		5,579,675		67,955			1	%
Transportation and Interruptible	1,549,940		1,518,536		31,404			2	%
Total Delivered Volumes	7,197,570		7,098,211		99,359			1	%
Heating Degree Days (Unofficial)	3,605		3,631		(26		)	(1	)%

Operating revenues for the six months ended March 31, 2019 increased over the same period last year due to the implementation of higher non-gas rates and higher gas costs. The Company placed new non-gas base rates into effect for natural gas service rendered on or after January 1, 2019, subject to refund. The new non-gas base rates were reflected in the Company's rate application with the SCC as filed in October 2018. The rates are subject to refund and the Company has recorded an estimated refund for the current quarter based on past history of rate awards approved by the SCC. The average commodity price of natural gas delivered during the first six months of fiscal 2019 was approximately 6% per decatherm higher than the same period last year. Natural gas commodity prices spiked during December due to weather, but have since returned to lower levels over the most recent quarter. The prior year included a reserve of $821,343 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate federal income tax rate. The current fiscal period reflects a reserve of $523,881 as the accrual for excess revenues ended with the implementation of new non-gas base rates, which incorporated the reduction in the federal income tax rate.

See the Regulatory and Tax Reform section below for more information.

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RGC RESOURCES, INC. AND SUBSIDIARIES

	Six Months Ended March 31,
	2019		2018		Increase		Percentage
Gas Utility Margin
Utility Revenues	$	46,095,330	$	43,128,570	$	2,966,760	7	%
Cost of Gas	24,677,797		23,304,683		1,373,114		6	%
Gas Utility Margin	$	21,417,533	$	19,823,887	$	1,593,646	8	%

Regulated natural gas margins from utility operations increased from the same period last year for the same reason that margins increased for the quarter, implementation of higher non-gas base rates. As a result, customer base charges and non-gas volumetric margins increased by $1,201,167 and $1,155,544, respectively, net of the estimated refund. SAVE revenues declined by $1,014,411 during the same period. The reserve for excess revenues related to the reduction in federal income taxes declined by $297,462.

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

	Six Months Ended March 31,
	2019			2018			Increase / (Decrease)
Customer Base Charge	$	7,449,762		$	6,248,595		$	1,201,167
Carrying Cost	274,567			310,441			(35,874		)
SAVE Plan	1,230,537			2,244,948			(1,014,411		)
Volumetric	13,037,227			11,881,683			1,155,544
WNA	(110,922		)	(123,765		)	12,843
Other Gas Revenues	60,243			83,328			(23,085		)
Excess Revenue Refund	(523,881		)	(821,343		)	297,462
Total	$	21,417,533		$	19,823,887		$	1,593,646

Operation and maintenance expenses increased by $519,450, or 8%, from the same period last year due to higher compensation costs, contracted services, bad debt expense and amortization of regulatory assets partially offset by higher capitalized overheads. Total compensation costs increased by $331,000 due to higher employment levels and wage increases. The Company incurred $83,000 in contracted services related to the periodic clearing of the natural gas transmition line right-of-way and scheduled maintenance at the LNG facility. The Company began amortizing certain regulatory assets beginning January 1, 2019 resulting in an additional $66,000 in expense. Bad debt expense increased by $22,000 related to increased customer billings. Total capitalized overheads increased by $69,000 due to increased capital expenditures offset by lower LNG production during the period.

General taxes increased by $91,046, or 9%, associated with higher property and payroll taxes. The increase in property taxes reflect the ongoing investment in the utility infrastructure of Roanoke Gas while the higher payroll taxes correspond to compensation activity.

Depreciation expense increased by $341,194, or 10%, on higher utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $920,900, due to the significant increase in the investment in the MVP project.

Other income (expense), net increased by $191,146 primarily due to the revenue sharing incentive mechanism approved in 2018, the reclassification of the components of net periodic benefit costs other than service cost from operations to a non-operating expense and timing of charitable contributions.

Interest expense increased by $463,600, or 37%, due to a 29% increase in total average debt outstanding and rising interest rates on the Company's variable-rate debt. Increased borrowing is attributable to the investment in MVP and funding of Roanoke Gas' capital budget. The weighted-average effective interest rate on total Company debt increased from 3.69% for the first six months of fiscal 2018 to 3.92% for the same period in fiscal 2019.

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Income tax expense declined by $383,286 due to a reduction in the federal income tax rate, the amortization of excess deferred taxes on the regulated operations of Roanoke Gas and the valuation adjustment to the deferred taxes of the unregulated operations in the prior year. The federal income tax rate declined from the 24.3% blended rate for fiscal 2018 to the statutory rate of 21% in fiscal 2019. As discussed above and in the Regulatory and Tax Reform section below, Roanoke Gas is amortizing the regulatory liability related to the excess deferred taxes on the regulated operations into income tax expense with a corresponding reduction in revenues. During the first quarter of fiscal 2018, Resources revalued the deferred taxes of its unregulated operations, which resulted in $208,000 direct charge to income tax expense.

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 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 adjustments for the effect of the TCJA includes estimates related to the revaluation of deferred income tax and the refund of excess billings to customers pending final review and approval by the SCC. The Company believes these adjustments to be reasonable estimates of the financial effect of the tax change on the regulated operations of the Company. However, these estimates will be adjusted, if necessary, once the SCC completes its audit and approves the Company's proposed rates and methodology. If the SCC proposes any adjustment, it could result in increased refund amounts for customers and reductions in revenue. The Company has also recorded an estimate for refund related to the implementation of the new non-gas base rates effective January 1, 2019. This estimate is based on the results of prior rate proceedings and will be adjusted upon filing of the SCC's staff report and the issuance of a final order on the rate application.

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

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, 2018.

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. In accordance with an SCC order issued in 2018, a portion of the utilization fee will be retained by the Company with the balance passed through to customers through reduced gas costs.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its wholly-owned subsidiary 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 FERC regulated natural gas pipeline connecting Equitran's gathering and transmission system in northern West Virginia to the Transco interstate pipeline in south central Virginia.

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 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 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.

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On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity. Furthermore, since January 2018, FERC has issued several Notices to Proceed ("NTP"), which granted the LLC permission to begin construction activities. Since construction began, the LLC has encountered several challenges which have delayed the project, including weather issues, pipeline protesters and legal challenges to various federal and state permits resulting in stop orders and FERC intervention. Construction activities were limited during the just completed winter season but have since resumed. Certain permits have been vacated or stayed, which currently prevents the LLC from working in stream crossings or wetlands. In addition, FERC issued a stop work order that directed all construction activity to cease within a 25-mile exclusion zone in and around the Jefferson National Forest. The LLC continues to work with all related regulatory entities and judicial bodies to resolve these issues. The LLC managing partner has stated that completing the project during 2019 is unlikely; however the LLC managing partner continues to target a full in-service date in the fourth quarter of 2019.

Initially, the total project cost was estimated to be $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution was expected to be approximately $35 million. As a result of the issues described above, the LLC revised the project cost to an estimated $4.6 billion with Midstream's estimated cash investment increasing to $46 million. Midstream negotiated amendments to its two 5-year unsecured Promissory Notes to increase borrowing limits from $38 million to $50 million. Midstream was able to obtain access to the additional capital with no changes to existing provisions under the notes.

Most of the current 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 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. As investment in the MVP grows, so will the amount of AFUDC recognized until the pipeline is placed in service. Earnings after the pipeline becomes operational will be derived from the fees charged for transporting natural gas through the pipeline.

In 2018, Midstream became a participant in the MVP Southgate project ("Southgate"), to construct a 70-mile pipeline extending from the MVP mainline at the Transco interconnect in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in the Southgate project and, based on current project cost estimates, will invest between $1.8 million and $2.5 million toward the project. Midstream's participation in the Southgate project is for investment purposes only. The Southgate in-service date is currently targeted for the end of calendar 2020.

Regulatory and Tax Reform

On October 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 incorporates into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs, recovery of regulatory assets associated with eligible safety activity costs ("ESAC") and approximately $4.7 million in annual SAVE plan revenues previously billed through the SAVE rider. The new non-gas base rates were placed into effect for gas service rendered on or after January 1, 2019, subject to refund, pending audit and final order by the SCC. The SCC staff is currently conducting their audit of the rate application, with their report expected by the end of June 2019. A hearing on the rate application is scheduled for August with a final order not expected until later in 2019.

Historically, the Company has not received the full rate increase requested in their rate applications. The SCC will conduct a thorough audit and make adjustments to the requests based on updated information, differences in assumptions, disallowance of certain costs and precedents set by rate awards at other companies. Therefore, management has recorded a provision for refund in current regulatory liabilities associated with these new non-gas rates. As there is currently not sufficient information to determine the full extent of proposed adjustments and recommendations by the SCC staff nor the ultimate result from the subsequent hearing, management based the refund reserve on previously approved rate awards as compared to initial rate requests. The actual refund could be more or less depending on the outcome of both the staff's audit and the hearing. As more information becomes available, the Company will refine its estimate for refund; however, the actual rate award will not be finalized until the SCC issues its order.

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 of Roanoke Gas. As Roanoke 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 for Roanoke 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 not

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violate the IRS 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. As of March 31, 2019, Roanoke Gas had approximately $11,200,000 in both current and non-current portions of the net regulatory liability.

The second regulatory liability relates to the excess revenues collected from customers. The non-gas base rates used since the passage of the TCJA in December 2017 through December 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 in January 2018, Roanoke Gas recorded an estimated refund for the excess revenues collected in fiscal 2018 and the first quarter of fiscal 2019.

Beginning with the implementation of the new non-gas base rates in January 2019, Roanoke Gas began returning the excess deferred income taxes over the 28-year period and the excess revenues to customers over a 12-month period. The estimated refund amounts for both the excess deferred taxes and the excess revenues associated with the reduction in the federal income tax rate are subject to review and adjustment by the SCC, which is being done in connection with their audit of the rate case application. The Company will record any such adjustments as required by an SCC order.

Since its last rate case, Roanoke Gas has deferred ESAC costs attributable to compliance and safety related expenses. These expenses were above and beyond a base line for those costs previously provided for in non-gas base rates and have been included in the current rate application for recovery over a five year period. If the SCC would deny recovery of any of these costs, Roanoke Gas would adjust the value of the regulatory assets to the amount that would ultimately be realized by the Company.

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 formal application for an increase in non-gas base rates. 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. On September 28, 2018, the SCC issued its order approving the 2019 SAVE Plan and SAVE rider effective January 1, 2019, focusing on the ongoing replacement of pre-1973 plastic pipe. All previous SAVE investment through December 31, 2018 has been incorporated into the rate application. The new SAVE Plan Rider reflects only the recovery of qualifying SAVE Plan investments made since the beginning of January 2019. As a result, the 2019 SAVE Plan Rider is expected to provide approximately $362,000 in revenue for the nine months ended September 30, 2019. In addition, the SCC also approved the true-up factor for the 2017 SAVE Plan, which will refund approximately $163,000 in excess SAVE Plan revenues to customers.

As noted above, Roanoke Gas contracts with a third party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for the right to utilize the excess capacities of the transportation and storage rights, the asset manager credits Roanoke Gas monthly for an amount referred to as a utilization fee. In June 2018, the SCC issued an order, retroactive to April 1, 2018, approving implementation of an incentive mechanism, whereby the Company shares the utilization fee with its customers. Under the incentive mechanism beginning April 1 each year, customers receive the initial $700,000 of the utilization fee collected through reduced gas costs, and thereafter, every additional dollar received during the annual period is split 25% to the Company and 75% to its customers.

On February 7, 2019, the SCC issued a final order granting a Certificate of Public Convenience and Necessity ("CPCN") to furnish gas service to all of Franklin County. If the Company does not furnish gas service to the area so designated within five years of the date of the order, the CPCN granting authority to serve Franklin County will be terminated.

Roanoke Gas' provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas every five years. The last depreciation study was completed and implemented in fiscal 2014. The Company is currently in the process of conducting a new depreciation study to incorporate all of the new and replacement infrastructure and equipment placed in service since the last study. The Company anticipates filing the new depreciation study with the SCC in June for review and approval. Once approved, any changes are expected to be implemented in the current fiscal year. The potential impact of the new depreciation study is not known at this time.

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

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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 $1,720,152 for the six-month period ended March 31, 2019, compared to a $4,776,934 increase for the same period last year. The following table summarizes the sources and uses of cash:

	Six Months Ended March 31,
	2019			2018
Cash Flow Summary
Net cash provided by operating activities	$	10,933,123		$	10,648,528
Net cash used in investing activities	(24,279,040		)	(13,851,993		)
Net cash provided by financing activities	15,066,069			7,980,399
Increase in cash and cash equivalents	$	1,720,152		$	4,776,934

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 six months of the fiscal year. Cash flow from operating activities increased over the same period last year by $284,595, primarily related to several offsetting items. Net income increased by nearly $1.6 million; however, a significant portion of the increase was attributable to the non-cash equity in earnings from the investment in MVP. Over-collections of gas cost increased by more than $2.6 million over the same period last year. Gas prices spiked in December and the futures prices indicated the natural gas commodity prices would remain at an elevated level during the winter months. Based on this information, the Company filed its quarterly PGA adjustment reflecting higher prices; however, commodity prices returned to lower levels during the second fiscal quarter resulting in the increase in over-collections. Accounts receivable balances increased by $2.7 million over the same period last year primarily as a result of the implementation of new non-gas rates and the higher gas cost component in the PGA factor. A summary of the cash provided by operations is provided below:

	Six Months Ended March 31,
Cash Flow From Operating Activities:	2019			2018			Increase / (Decrease)
Net income	$	7,104,252		$	5,525,391		$	1,578,861
Depreciation	3,880,945			3,531,558			349,387
Equity in earnings	(1,261,224		)	(340,324		)	(920,900		)
Increase in over/under-collections	3,597,239			960,706			2,636,533
Decrease in gas in storage	5,722,919			5,833,985			(111,066		)
Increase in accounts receivable	(8,232,925		)	(5,516,423		)	(2,716,502		)
Increase in regulatory liability and deferred taxes	143,399			851,075			(707,676		)
Other	(21,482		)	(197,440		)	175,958
Net Cash Provided by Operations	$	10,933,123		$	10,648,528		$	284,595

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 peak shaving plant and distribution system facilities, expanding the 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. In addition, the Company is constructing two interconnect stations to access the Mountain Valley Pipeline, which will provide additional gas supply to the Company's distribution system as well as provide access to currently unserved areas. Total capital expenditures for the first six months were nearly $11 million, which represented a $900,000 increase over the same period last year. Capital expenditures for fiscal 2019 are expected to be near last year's level of $23.3 million.

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RGC RESOURCES, INC. AND SUBSIDIARIES

Investing cash flows also include the Company's continued funding of its participation in the MVP, with a total cash investment of more than $13.3 million for the six months ended March 31, 2019 compared to $3.8 million for the corresponding period last year. Due to cold weather and wet conditions, pipeline activity was limited during the winter season. Construction activities on the MVP should resume during the spring and summer months as the LLC managing partner continues to project an in-service date by the end of calendar 2019.

Financing activities generally consist of long-term notes payable and line-of-credit borrowings and repayments, issuance of stock and the payment of dividends. Cash flows provided by financing activities were $15.1 million for the current period compared to $8 million for the same period last year. The increase in financing cash flows is primarily attributable to the borrowings under Midstream's credit facility to finance its investment in MVP and the issuance of notes by Roanoke Gas. The Company borrowed $13,979,000 under the Midstream credit facility compared to $3,951,000 for the same period last year. In addition, Roanoke Gas issued $10 million in notes to refinance the line-of-credit balance, which provides bridge financing for its capital projects. During the prior fiscal year, the Company realized more than $15 million in net proceeds from the issuance of 700,000 shares of common stock and issued $8 million in notes, both of which were used to pay down the line-of-credit balance and finance Roanoke Gas' capital expenditures.

On March 28, 2019, Roanoke Gas issued notes in the aggregate principal amount of $10 million. These notes have a 12-year term with a fixed interest rate of 4.41%.

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement with a two-year term expiring March 31, 2021, replacing the prior line-of-credit agreement scheduled to expire March 31, 2020. 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 maintains the multi-tiered borrowing limits to accommodate the seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the agreement range from $3,000,000 to $30,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current.

On February 19, 2019, Midstream entered into an agreement with the lending institutions to amend its existing credit agreement and related notes that provide financing for the MVP project. The amendment increased total borrowing limits to $50 million through the date of maturity to meet the projected funding requirements for completion of the MVP. With the exception of the increase in borrowing limits, all remaining terms under the notes remain unchanged including the variable-interest rate based on 30-day LIBOR plus 135 basis points.

As of March 31, 2019, Resources' long-term capitalization ratio was 49.3% equity and 50.7% debt.

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RGC RESOURCES, INC. AND SUBSIDIARIES

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 March 31, 2019, the Company had no outstanding balance under its variable rate line-of-credit with an average balance outstanding during the six-month period of $11,124,415. The Company also had $31,722,200 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 six months ended March 31, 2019 would have resulted in an increase of approximately $199,000 in interest expense for the period. 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 March 31, 2019, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 535,293 decatherms of gas in storage, including LNG, at an average price of $3.56 per decatherm, compared to 514,917 decatherms at an average price of $3.63 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.

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RGC RESOURCES, INC. AND SUBSIDIARIES

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.

As of March 31, 2019, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2019.

Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fiscal quarter ended March 31, 2019, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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RGC RESOURCES, INC. AND SUBSIDIARIES

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

None.

ITEM 1A – RISK FACTORS

There have been no material changes from the risk factors previously disclosed in Resources' Annual Report on Form 10-K for the year ended September 30, 2018.

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

Number	Description
10.1	Gas Transportation Agreement, for use under FT-A rate schedule, between Midwestern Gas Transmission Company and Roanoke Gas Company dated March 11, 2019.
10.2	Certificate of Public Convenience and Necessity for Franklin County dated March 5, 2019.
10.3	Second Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank & Trust and Branch Banking and Trust dated February 19, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on February 19, 2019).
10.4	Amended and Restated Note in the principal amount of $30,000,000 in favor of Union Bank & Trust due December 29, 2020 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on February 19, 2019).
10.5	Amended and Restated Note in the principal amount of $20,000,000 in favor of Branch Banking and Trust due December 29, 2020 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on February 19, 2019).
10.6	Revolving Line of Credit Note in the original principal amount of $30,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated as of March 26, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on March 28, 2019).
10.7	Third Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated as of March 26, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on March 28, 2019).
10.8	Unsecured Note in the original principal amount of $5,000,000 by and between Roanoke Gas and Highmark, Inc. dated March 28, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on March 29, 2019).
10.9	Unsecured Note in the original principal amount of $3,000,000 by and between Roanoke Gas and Prudential Arizona Reinsurance Term Company dated March 28, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on March 29, 2019).
10.10	Unsecured Note in the original principal amount of $2,000,000 by and between Roanoke Gas and The Prudential Insurance Company of America dated March 28, 2019 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on March 29, 2019).
10.11	Unconditional Guaranty Agreement by and between RGC Resources, Inc. and Prudential Investment Management and each of Prudential Affiliates which is a party to the borrowings (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on March 29, 2019).
31.1	Rule 13a–14(a)/15d–14(a) Certification of Principal Executive Officer.
31.2	Rule 13a–14(a)/15d–14(a) Certification of Principal Financial Officer.
32.1*	Section 1350 Certification of Principal Executive Officer.
32.2*	Section 1350 Certification of Principal Financial Officer.
101	The following materials from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at March 31, 2019 and September 30, 2018, (ii) Condensed Consolidated Statements of Income for the three months and six months ended March 31, 2019 and 2018; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and six months ended March 31, 2019 and 2018; (iv) Condensed Consolidated Statements of Changes in Stockholders' Equity for the three months and six months ended March 31, 2019 and 2018; (v) Condensed Consolidated Statements of Cash Flows for the three months and six months ended March 31, 2019 and 2018, and (vi) Condensed Notes to Condensed Consolidated Financial Statements.

* These certifications are being furnished solely to accompany this quarterly report pursuant to 18 U.S.C. Section 1350, and are not being filed for purposes of Section 18 of the Securities Exchange Act of 1934 and are not to be incorporated by reference into any filing of the Registrant, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

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RGC RESOURCES, INC. AND SUBSIDIARIES

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.

		RGC Resources, Inc.
Date: May 6, 2019	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Secretary, Treasurer and CFO

35

EX-10.1

Midwestem Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreement (FT-A/FT-GS) VolumeNo. I ,v. 2.0.0 superseding v. 1.0.0 Page I of5 MIDWESTERN GAS TRANSMISSION COMPA}TY FIRM TRAhISPORTATION AGREEMENT Rate Schedule FT-A or FT-GS It<s THIS AGREEMENT (Agreement No. FA0016) is made and entered into as of March ll. 20!!,by and between MIDWESTERN GAS TRANSMISSION COMPANY, hereinafter referred to as "Company," and ROANOIG GAS COMPANY . hereinafter refened to as "Customer." Company and Customer shall be collectively rsfened to as "Parties." WITNESSETH: That, in consideration of their respective covenants and agreements herein contained, Company and Customer agre€ as follows: ARTICLE I -DEFIMTIONS The definitions found in Section I of the General Terms and Conditions of Company's FERC Gas Tariff are incorporated herein by reference. ARTICLE 2 . TRANSPORTATION Company agrees to provide firm transportation service pursuant to Rate Schedule FT-A or FT-GS to Customer on a daily basis beginning with Customer's Billing Commencement Date and continuing throughout the term of this Agreement in accordance with the Transportation Quantity and Transportation Path as identified on Exhibit A attached hereto. ARTICLE 3 - RECEIPT POINT A]{D DELIVERY POINT 3.1 The Receipt Point and Delivery Point defining the Transportation Path shall be those points specified on Exhibit A attached hereto. Customer shall be entitled to Receipt Point and Delivery Point flexibility in accordance with Section 15 of the General Terms and Conditions of Company's FERC Gas Tariff. Priority of transportation service shall be determined in accordance with Section 15 and Subsection 3.7 of the General Terms and Conditions oiCompany's FERC Gas Tariff. 3.2 Customer may request a change to the Receipt Point and/or Delivery Point defining the Transportation Path provided in this Agreement in accordance with Subsection 25.3 of the General Terms and Conditions of Company's FERC Gas Tariff. ARTICLE 4 . FACILITTES All facilities are in place to render the service provided for in this Agreement. or (If facilities are contemplated to be constructed, a brief description of the facilities will be included, as well as who is to construct, own and/or operate such facilities.) Tariff Section Issued: May7,201,5 Tariff Section Effective: June 8, 2015

Midwestern Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreement (FT-A/FT-GS) VolumeNo. I v. 2.0.0 superseding v. 1.0.0 Page 2 of5 ARTICLE 5 - QUALITY SPECIFICATIONS A}ID STA}.TDARDS FOR MEASTJREMENTS {K: For all gas received, transported and delivered hereunder, the Parties agree to the quality specifications and standards for measurement as provided for in the General Terms and Conditions of Company's FERC Gas Tariff. Company shall be responsible for the operation of measurement facilities at the Delivery Point and at the Receipt Point. In the event that measurement facilities are not operated by Company, then the responsibility for operations shall be deemed to be that of the Balancing Party at such point. If measurement facilities are not operated by Company and there is no Balancing Party at such point, then the responsibility for operations shall be deemed to be Customer's. ARTICLE 6 - RATES FOR SERVICE 6.1 Transportation Charge - The rates, charges and surcharges for the transportation service provided for herein, including compensation for system fuel use and gas lost and unaccounted for, shall be paid by Customer to Company in accordance with Company's applicable effective Rate Schedule (FT-A or FT-GS) and the General Terms and Conditions of Company's FERC Gas Tariff. Except as provided in this Agreement, Customer shall pay Company the applicable Maximum Rate and all other applicable charges and surcharges specified on the effective Summary of Rates and Charges in Company's FERC Gas Tariff. Company and Customer may agree to a discounted rate pursuant to the provisions of Section 27 of the General Terms and Conditions of Company's FERC Gas Tariff provided that the discounted rate is between the applicable Maximum and Minimum Rates for this service. 6.2 Incidental Charges - Customer agrees to pay Company for all known and anticipated filing fees, reporting fees or similar charges required to provide the transportation service described herein. Further, Customer agrees to reimburse Company for all such fees within thirty (30) days after receiving proof of payment from Company. 6.3 Changes in Tariff Provisions - Company shall have the right to file with the Federal Energy Regulatory Commission (FERC) any changes in the rates, charges, terms and conditions of its Rate Schedules, the General Terms and Conditions, or form of agreements in Company's FERC Gas Tariff applicable to those Rate Schedules and to make such changes effective at such times as Company desires and is possible under applicable law. Compary agrees that Customer may protest any filed changes before the FERC and exercise any other rights it may have with respect thereto. ARTICLE 7 . RESPONSIBILITY DURING TRANSPORTATION As between the Parties hereto, it is agreed that from the time gas is delivered by Customer to Company at the Receipt Point(s) and prior to delivery of such gas to or for the account of Customer at the Delivery Point(s), Company shall have the unqualified right to commingle such gas with other gas in its system and shall have the unqualified right to handle and treat such gas as its own. Without limiting its other responsibilities and obligations under this Agreernent, the Customer acknowledges that it is responsible for obtaining and assumes the risk of loss of the following: ( I ) gas supply, (2) markets and (3) transportation upstream and downstream of the Company's pipeline syst€m. Notwithstanding the loss of one or more of the items enumerated above, Customer shall continue to be liable for payment to the Company of the applicable rates and charges as provided for in this Agreement and Company's FERC Gas Tariff. Tariff Section Issued: May 7 , 2015 TariffSection Effective: June 8, 2015

Midwestern Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreement (FT-A/FT-GS) VolumeNo. I v. 2.0.0 superseding v. 1.0.0 Page 3 of5 ARTICLE 8 - PAYMENTS PKS Customer shall make payments to Company under this Agreement in accordance with the provisions of this Agreement and Section 6 of the General Terms and Conditions of Company's FERC Gas Tariff as such Tariff may be revised or replaced from time to time. ARTICLE 9 - RATE SCTIEDULES, GENERAL TERMS AND CONDITIONS AND DCIIBIT A OF AGREEMENT Company's Rate Schedules and General Terms and Conditions, which are on file with the FERC and in effect, and Exhibit A hereto are all applicable to this Agreement and are hereby incorporated by reference and made part of this Agreement. To the extent a term or condition set forth in this Agreement is inconsistent with the General Terms and Conditions, the General Terms and Conditions shall govern. Furthermore, to the extent a term or condition set forth in this Agreement is inconsistent with the applicable Rate Schedule, the Rate Schedule shall govern unless the relevant provision is inconsistent with General Terms and Conditions. ARTICLE IO - REGTILATION l0.l This Agreement shall be subject to all applicable and lawful United States governmental statutes, orders, rules and regulations of duly constituted authorities having jurisdiction and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorization upon terms acceptable to Company. This Agreement shall be void and of no force and effect if any necessary regulatory approval or authorization is not so obtained or continued All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 10.2 In the event the Parties are unable to obtain all necessary and satisfactory regulatory approvals for service on facilities prior to the expiration oftwo (2) years from the effective date hereof, then, prior to receipt of such regulatory approvals, either Party may terminate this Agreement by giving the other Parfy at least thirty (30) days prior written notice, and the respective obligations hereunder, except for the provisions of Article 6.2 herein, shall be of no force and effect from and after the effective date of such termination. ARTICLE 1I - WARRA}ITIES Customer agrees to indemnifo and hold Company harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including rsasonable attorneys fees) arising from or out of breach of any warranty, expross or implied, by Customer herein. Company shall not be obligated to provide or continue service hereunder in the event of any breach of warranty by Customer. ARTICLE 12 - TERM OF AGREEMENT 12.1 This Agreement shall become effective upon its execution and shall, under all circumstances, continue in effect in accordance with Company's FERC Gas Tariff after the Billing Commencement Date as set forth in Exhibit A or through October 31. 2024. If the primary term of this Agreement shall be one year or more, then this Agreement shall continue in effect thereafter until extended or terminated in accordance with Sections 16 or 17 of the General Terms and Conditions of Company's Tariff Section Issued: lNlay7,2015 Tariff Section Effective: June 8, 2015

Midwestem Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreement (FT-A/FT-GS) VolumeNo. I v. 2.0.0 superseding v. 1.0.0 (rs Page 4 of5 FERC Gas Tariff. Service rendered pursuant to this Agreement shall be abandoned upon termination of this Agreement. 12.2 Termination of this Agreement shall not relieve Company and Customer of the obligation to resolve or cash-out any imbalances hereunder, or Customer ofits obligation hereunder to Company and shall be in addition to any other remedies that Company may have. 12.3 In addition to any other remedy Company may have, this Agreement will terminate automatically in the event Customer fails to pay the entire amount of any invoice for service rendered by Company hereunder when that amount is due, provided Company shall give Customer thirty days' notice prior to any termination of service. Service may continue hereunder if within the thirty day notice period satisfactory assurance of payment is made in accordance with the terms and conditions of Section 6 of the General Terms and Conditions of Company's FERC Tariff ARTICLE 13.NOTICES Any notice, request, demand, statement, or invoice provided for in this Agreement or any notice that either Party may desire to give to the other shall be in accordance with Subsection 11.1 of the General Terms and Conditions of Company's FERC Gas Tariff. ARTICLE 14 . SUCCESSORS AND ASSIGNS l4.l Either Party,may assign or pledge this Agreement and atl rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument that it has executed or may execute hereafter as security for indebtedness. Either Party, without relieving itselfofits obligations under this Agreement, may assign any of its rights hereunder to a company with which it is affiliated, subject to any required regulatory approvals. Otherwise, Customer shall not assign this Agreement or any of its rights and obligations hereunder, except in accordance with Section 2l of the General Terms and Conditions of Company's FERC Gas Tariff. 14.2 Any person or entify that succeeds by purchase, mergeq or consolidation to the properties, substantially or as an entirety, ofeither Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. Customer and any such successor must obtain any required regulatory approvals to make such assignment or transfer. ARTICLE 15 - GENERAL l5.l Except for changes specifically authorized pursuant to this Agreement, no modification of or supplement to the terms and conditions hereof shall be or become effective until Customer has submitted a request for change and Customer has been notified of Company's agreement to such change. 15.2 No waiver by any Party of any one or more defaults by the other in the performance of any provision of this Agreement shall operate or be construed as a waiver of any future default or defaults, whether ofa like or ofa different character. 15.3 The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Oklahoma, without regard to Choice of Law doctrine that refers to the laws of another jurisdiction. 15.4 If any provision of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at Company's option; and if the Tariff Section Issued: May7,2015 Tariff Section Effective: June 8, 2015

Midwestem Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreernent (FT-A/FT-GS) VolumeNo. I v. 2.0.0 superseding v. 1.0.0 Page 5 of5 severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. ARTICLE 16 - OTIIERPROVISIONS (If none so state) NONE IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written. MIDWESTERN TRANSMISSION COMPANY By: Title: t)/h81tul ROANOKEGAS COMPANY (NAME /u By: Title PPssertf Prrs Tariff Section Issued: May 7 ,2015 Tariff Section Effective: June 8, 2015

Midwestern Gas Transmission Company Part 9.10 FERC Gas Tariff Firm Transportation Agreement (FT-A/FT-GS) Volume No. I v. 2.0.0 superseding v. 1.0.0 Page I of I MIDWESTERN GAS TRANSMISSION COMPANY EXHIBIT A TO FIRM TRANSPORTATION AGREEMENT Rate Schedule FT-A or FT-GS COMPANY: Midwestern Gas Transmission Company COMPANY'S ADDRESS: ONEOK Plaza 100 West 5th Street Tulsa, Oklahoma 74103 CUSTOMER: Roanoke Gas Company CUSTOMER'S ADDRESS: 519 Kimball Avenue. N.E. Roanoke. VA 24016 Right of First Refusal: Yes X No n Transportation Quantity: 3/ 5.293 Dth/day Transportation Path: Receipt Point: Channahon Delivery Point: Portland Recourse Rate: Maximum Rate 1/ X Discounted Rate(s): l/ ! RateType:213/ Quantity: Quantity Level Time Period: Start Date End Date Contract:DiscountedMonthlyReservationRateperDth- Discounted Daily Commodity Rate per Dth Point: Receipt Point Delivery Point Point to Point: Receipt Point to Delivery Point Zone: Receipt Point to Delivery Point Relationship Rate Component: Index Price Differential: Negotiated Rate: 1/No X Yes n ($/Dth) (attach explanation of rate) This Exhibit A is made and entered into as of March I l, 2019. Billing Commencement Date of this Exhibit A is November I ,2019_. (This Exhibit A supersedes and cancels Exhibit A dated November l. 1999 to the Firm Transportation Agreement dated November I. 1999.) l/ An applicable ACA charge will be included in the Customer's monthly invoice. 2/ See Section 27 of Ihe General Terms and Conditions for description of various types of discount rates. 3/ In the event there are multiple receipt points and/or delivery points, supplement this section to present the transportation quantity or discounted rate information for each point. Agreement No. FA00l6 Tariff Section Issued: May 7,2015 Tariff Section Effective: June 8,2015

EX-10.2

EX-31.1

RGC RESOURCES, INC. AND SUBSIDIARIES

EXHIBIT 31.1

CERTIFICATION

I, John S. D'Orazio, certify that:

1. I have reviewed this quarterly report on Form 10-Q of RGC Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2019	/s/ John S. D'Orazio
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

RGC RESOURCES, INC. AND SUBSIDIARIES

EXHIBIT 31.2

CERTIFICATION

I, Paul W. Nester, certify that:

1. I have reviewed this quarterly report on Form 10-Q of RGC Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2019	/s/ Paul W. Nester
	Vice President, Secretary, Treasurer and Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

RGC RESOURCES, INC. AND SUBSIDIARIES

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of RGC Resources, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John S. D'Orazio, President and Chief Executive Officer of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ John S. D'Orazio

John S. D'Orazio

President and Chief Executive Officer

(Principal Executive Officer)

Date: May 6, 2019

EX-32.2

RGC RESOURCES, INC. AND SUBSIDIARIES

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of RGC Resources, Inc. (the “Company”) on Form 10-Q for the period ended March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul W. Nester, Vice President, Secretary, Treasurer and Chief Financial Officer of the Company, certify to my knowledge, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Paul W. Nester

Paul W. Nester

Vice President, Secretary, Treasurer and Chief Financial Officer

(Principal Financial Officer)

Date: May 6, 2019

XML

Document and Entity Information - shares	6 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Registrant Name	RGC RESOURCES INC
Entity Central Index Key	0001069533
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		8,045,409

XML

Condensed Consolidated Balance Sheets - USD ($)	Mar. 31, 2019	Sep. 30, 2018
CURRENT ASSETS:
Cash and cash equivalents	$ 1,967,563	$ 247,411
Accounts receivable (less allowance for uncollectibles of $377,372 and $103,573, respectively)	11,872,956	3,913,830
Materials and supplies	960,565	913,889
Gas in storage	1,904,277	7,627,196
Prepaid income taxes	0	837,683
Under-recovery of gas costs	0	922,898
Interest rate swap	54,786	100,723
Other	1,662,857	980,972
Total current assets	18,423,004	15,544,602
UTILITY PROPERTY:
In service	229,700,422	224,854,320
Accumulated depreciation and amortization	(65,761,219)	(63,099,306)
In service, net	163,939,203	161,755,014
Construction work in progress	9,997,035	4,208,614
Utility plant, net	173,936,238	165,963,628
OTHER ASSETS:
Regulatory assets	8,769,840	8,862,147
Investment in unconsolidated affiliates	36,276,548	28,507,146
Interest rate swap	86,745	209,840
Other	515,632	472,743
Total other assets	45,648,765	38,051,876
TOTAL ASSETS	238,008,007	219,560,106
CURRENT LIABILITIES:
Dividends payable	1,334,680	1,242,753
Accounts payable	5,326,625	5,211,032
Capital contributions payable	3,346,681	10,142,766
Customer credit balances	459,840	1,003,622
Income taxes payable	521,764	0
Customer deposits	1,560,403	1,421,043
Accrued expenses	3,372,121	3,750,466
Over-recovery of gas costs	2,674,341	0
Regulatory liability	2,785,993	1,320,167
Total current liabilities	21,382,448	24,091,849
LONG-TERM DEBT:
Notes payable	87,222,200	63,243,200
Line-of-credit	0	7,361,017
Less unamortized debt issuance costs	(317,235)	(282,281)
Long-term debt net of unamortized debt issuance costs	86,904,965	70,321,936
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	6,567,409	6,417,948
Regulatory cost of retirement obligations	11,770,061	11,163,981
Benefit plan liabilities	3,742,555	3,947,967
Deferred income taxes	11,953,317	12,585,577
Regulatory liability - deferred income taxes	10,712,735	11,447,736
Total deferred credits and other liabilities	44,746,077	45,563,209
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 8,043,272 and 7,994,615, respectively	40,216,360	39,973,075
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	0	0
Capital in excess of par value	13,868,387	13,043,656
Retained earnings	31,890,788	27,438,049
Accumulated other comprehensive loss	(1,001,018)	(871,668)
Total stockholders’ equity	84,974,517	79,583,112
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 238,008,007	$ 219,560,106

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($)	Mar. 31, 2019	Sep. 30, 2018
Statement of Financial Position [Abstract]
Accounts receivable, allowance for uncollectibles	$ 377,372	$ 103,573
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	8,043,272	7,994,615
Common stock, share outstanding	8,043,272	7,994,615
Preferred stock, par value (in dollars per share)	$ 0	$ 0
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Preferred stock, share outstanding	0	0

XML

Condensed Consolidated Statements of Income - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
OPERATING REVENUES:
Operating revenues	$ 25,274,959	$ 24,917,973	$ 46,491,706	$ 43,674,024
OPERATING EXPENSES:
Operations and maintenance	3,714,084	3,488,889	7,236,083	6,716,633
General taxes	556,336	506,857	1,064,225	973,179
Depreciation and amortization	1,905,475	1,734,878	3,810,950	3,469,756
Total operating expenses	19,071,476	19,641,888	37,024,001	34,753,448
OPERATING INCOME	6,203,483	5,276,085	9,467,705	8,920,576
Equity in earnings of unconsolidated affiliate	698,175	191,513	1,261,224	340,324
Other income (expense), net	121,709	41,948	247,595	56,449
Interest expense	892,649	633,186	1,709,431	1,245,831
INCOME BEFORE INCOME TAXES	6,130,718	4,876,360	9,267,093	8,071,518
INCOME TAX EXPENSE	1,460,628	1,410,431	2,162,841	2,546,127
NET INCOME	$ 4,670,090	$ 3,465,929	$ 7,104,252	$ 5,525,391
BASIC EARNINGS PER COMMON SHARE (in dollars per share)	$ 0.58	$ 0.47	$ 0.89	$ 0.76
DILUTED EARNINGS PER COMMON SHARE (in dollars per share)	0.58	0.47	0.88	0.75
DIVIDENDS DECLARED PER COMMON SHARE (in dollars per share)	$ 0.165	$ 0.155	$ 0.33	$ 0.31
Gas Utility [Member]
OPERATING REVENUES:
Operating revenues	$ 25,058,749	$ 24,608,576	$ 46,095,330	$ 43,128,570
OPERATING EXPENSES:
Cost of gas and sales	12,771,338	13,743,277	24,677,797	23,304,683
Non Utility [Member]
OPERATING REVENUES:
Operating revenues	216,210	309,397	396,376	545,454
OPERATING EXPENSES:
Cost of gas and sales	$ 124,243	$ 167,987	$ 234,946	$ 289,197

XML

Condensed Consolidated Statements of Comprehensive Income - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 4,670,090	$ 3,465,929	$ 7,104,252	$ 5,525,391
Other comprehensive income (loss), net of tax:
Interest rate swap	(44,121)	61,773	(125,524)	106,418
Defined benefit plans	(1,913)	(4,249)	(3,826)	(8,498)
Other comprehensive loss	(46,034)	57,524	(129,350)	97,920
COMPREHENSIVE INCOME	$ 4,624,056	$ 3,523,453	$ 6,974,902	$ 5,623,311

XML

Condensed Consolidated Statements of Changes in Stockholders' Equity Condensed Consolidated Statements of Changes in Stockholders' Equity - USD ($)	Total	Common Stock	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period at Sep. 30, 2017	$ 60,040,472	$ 36,204,230	$ 292,485	$ 24,746,021	$ (1,202,264)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,059,462			2,059,462
Other comprehensive income (loss)	40,396				40,396
Cash dividends declared	(1,125,804)			(1,125,804)
Issuance of common stock	286,509	50,840	235,669
Balance at end of period at Dec. 31, 2017	61,301,035	36,255,070	528,154	25,679,679	(1,161,868)
Balance at beginning of period at Sep. 30, 2017	60,040,472	36,204,230	292,485	24,746,021	(1,202,264)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	5,525,391
Other comprehensive income (loss)	97,920
Balance at end of period at Mar. 31, 2018	79,299,226	39,876,960	12,617,409	27,909,201	(1,104,344)
Balance at beginning of period at Dec. 31, 2017	61,301,035	36,255,070	528,154	25,679,679	(1,161,868)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	3,465,929			3,465,929
Other comprehensive income (loss)	57,524				57,524
Cash dividends declared	(1,236,407)			(1,236,407)
Issuance of common stock	15,711,145	3,621,890	12,089,255
Balance at end of period at Mar. 31, 2018	79,299,226	39,876,960	12,617,409	27,909,201	(1,104,344)
Balance at beginning of period at Sep. 30, 2018	79,583,112	39,973,075	13,043,656	27,438,049	(871,668)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,434,162			2,434,162
Other comprehensive income (loss)	(83,316)				(83,316)
Cash dividends declared	(1,322,335)			(1,322,335)
Issuance of common stock	348,117	85,175	262,942
Balance at end of period at Dec. 31, 2018	80,959,740	40,058,250	13,306,598	28,549,876	(954,984)
Balance at beginning of period at Sep. 30, 2018	79,583,112	39,973,075	13,043,656	27,438,049	(871,668)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	7,104,252
Other comprehensive income (loss)	(129,350)
Balance at end of period at Mar. 31, 2019	84,974,517	40,216,360	13,868,387	31,890,788	(1,001,018)
Balance at beginning of period at Dec. 31, 2018	80,959,740	40,058,250	13,306,598	28,549,876	(954,984)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	4,670,090			4,670,090
Other comprehensive income (loss)	(46,034)				(46,034)
Cash dividends declared	(1,329,178)			(1,329,178)
Issuance of common stock	719,899	158,110	561,789
Balance at end of period at Mar. 31, 2019	$ 84,974,517	$ 40,216,360	$ 13,868,387	$ 31,890,788	$ (1,001,018)

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Condensed Consolidated Statements of Changes in Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividends declared per share (in dollars per share)	$ 0.165	$ 0.165	$ 0.155	$ 0.155
Common stock issued (in shares)	31,622	17,035	724,378	10,168

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Condensed Consolidated Statements of Cash Flows - USD ($)	6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 7,104,252	$ 5,525,391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	3,880,945	3,531,558
Cost of retirement of utility plant, net	(123,237)	(126,686)
Equity in earnings of unconsolidated affiliate	(1,261,224)	(340,324)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately	1,332,387	2,058,589
Net cash provided by operating activities	10,933,123	10,648,528
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(10,975,996)	(10,065,690)
Investment in unconsolidated affiliate	(13,304,263)	(3,804,844)
Proceeds from disposal of equipment	1,219	18,541
Net cash used in investing activities	(24,279,040)	(13,851,993)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	23,979,000	11,951,000
Borrowings under line-of-credit agreement	23,308,642	19,533,761
Repayments under line-of-credit agreement	(30,669,659)	(37,325,521)
Debt issuance costs	(60,343)	0
Proceeds from issuance of stock	1,068,016	15,997,654
Cash dividends paid	(2,559,587)	(2,176,495)
Net cash provided by financing activities	15,066,069	7,980,399
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,720,152	4,776,934
BEGINNING CASH AND CASH EQUIVALENTS	247,411	69,640
ENDING CASH AND CASH EQUIVALENTS	1,967,563	4,846,574
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	1,549,778	1,014,517
Income taxes paid	$ 1,623,000	$ 635,000

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Basis of Presentation

6 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

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.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly Resources' financial position as of March 31, 2019 and the results of its operations, cash flows, comprehensive income and changes in stockholders' equity for the three and six months ended March 31, 2019 and 2018. The results of operations for the three and six months ended March 31, 2019 are not indicative of the results to be expected for the fiscal year ending September 30, 2019 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The unaudited condensed consolidated interim financial statements and condensed notes are presented as permitted under the rules and regulations of the Securities and Exchange Commission. Pursuant to those rules, certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures are adequate to make the information not misleading. Therefore, the condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K for the year ended September 30, 2018. The September 30, 2018 balance sheet was included in the Company’s audited financial statements included in Form 10-K.

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.

The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements in Form 10-K for the year ended September 30, 2018. Newly adopted and newly issued accounting standards are discussed below.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This reclassification does not change net income and makes the Company's income statement presentation consistent with industry peers.

Recently Issued or 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 standard is effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period.

The Company adopted ASU 2014-09 and all amendments beginning in the quarter ended December 31, 2018. 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 further information.

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 beginning with the quarter ended December 31, 2018. The new guidance did not have a material effect on the Company's financial position, results of operations or cash flows.

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. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. 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. In January 2018, the FASB issued ASU 2018-01, which provides a practical expedient that allows entities the option of not evaluating existing land easements under the new lease standard for those easements that were entered into prior to adoption. New or modified land easements will require evaluation on a prospective basis. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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. The Company adopted the new guidance effective October 1, 2018. As a result, the Company now presents the other components of net periodic benefit costs outside of operations under the category of "other income (expense), net" in the condensed consolidated income statement. As the new guidance related to the expense classification was implemented on a retrospective basis, adjustments were made to the prior period financial statements as follow:

	Three Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	3,458,256		$	30,633		$	3,488,889
Total operating expenses	19,611,255			30,633			19,641,888
Operating income	5,306,718			(30,633		)	5,276,085
Other income (expense), net	11,315			30,633			41,948
Income before income taxes	$	4,876,360		$	—		$	4,876,360
	Six Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	6,655,367		$	61,266		$	6,716,633
Total operating expenses	34,692,182			61,266			34,753,448
Operating income	8,981,842			(61,266		)	8,920,576
Other income (expense), net	(4,817		)	61,266			56,449
Income before income taxes	$	8,071,518		$	—		$	8,071,518

In addition, the ASU allows only the service cost component of net periodic benefit cost to be eligible for capitalization when applicable. Previously, the Company included all components of net periodic benefit costs for capitalization. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company adopted the capitalization change prospectively on October 1, 2018. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits are not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. The adoption of this new guidance does not have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. 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 has not completed its evaluation of the new guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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.

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Revenue

6 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

The Company assesses new contracts and identifies related performance obligations for promises to transfer distinct goods or services to the customer. Revenue is recognized when performance obligations have been satisfied. In the case of Roanoke Gas, the Company contracts with its customers for the sale and/or delivery of natural gas.

The following tables summarize revenue by customer, product and income statement classification:

	Three months ended March 31, 2019								Three months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	15,397,504		$	—	$	15,397,504		$	15,479,644		$	—	$	15,479,644
Commercial	8,357,598			—		8,357,598			8,504,212			—		8,504,212
Industrial and Transportation	1,249,316			—		1,249,316			1,137,874			—		1,137,874
Revenue reductions (TCJA) (1)	—			—		—			(358,901		)	—		(358,901		)
Other	108,418			216,210		324,628			148,505			309,397		457,902
Total contracts with customers	25,112,836			216,210		25,329,046			24,911,334			309,397		25,220,731
Alternative Revenue Programs	(54,087		)	—		(54,087		)	(302,758		)	—		(302,758		)
Total operating revenues	$	25,058,749		$	216,210	$	25,274,959		$	24,608,576		$	309,397	$	24,917,973
	Six months ended March 31, 2019								Six months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	28,410,332		$	—	$	28,410,332		$	26,700,554		$	—	$	26,700,554
Commercial	15,700,155			—		15,700,155			14,820,511			—		14,820,511
Industrial and Transportation	2,475,364			—		2,475,364			2,265,677			—		2,265,677
Revenue reductions (TCJA) (1)	(523,881		)	—		(523,881		)	(821,343		)	—		(821,343		)
Other	334,908			396,376		731,284			393,770			545,454		939,224
Total contracts with customers	46,396,878			396,376		46,793,254			43,359,169			545,454		43,904,623
Alternative Revenue Programs	(301,548		)	—		(301,548		)	(230,599		)	—		(230,599		)
Total operating revenues	$	46,095,330		$	396,376	$	46,491,706		$	43,128,570		$	545,454	$	43,674,024
(1) Accrued refund associated with excess revenue collected in tariff rates associated with the reduction in federal income tax rates. See Note 4 for more information.

Gas utility revenues

Substantially all of Roanoke Gas’ revenues are derived from rates authorized by the Virginia State Corporation Commission ("SCC") as reflected in its tariffs. Based on its evaluation of ASC 606, the Company has concluded that these tariff-based revenues fall within the scope of ASC 606. Tariff rates represent the transaction price. Performance obligations created under these tariff-based sales include commodity (the cost of natural gas sold to customers) and delivery (transporting natural gas through the Company’s distribution system to customers). The sale and/or delivery of natural gas to customers result in the satisfaction of the Company’s performance obligation over time as natural gas is delivered.

All customers are billed each month based on consumption as measured by metered usage. Revenue is recognized as bills are issued for natural gas that has been delivered or transported to customers. In addition, the Company utilizes the practical expedient that allows an entity to recognize the invoiced amount as revenue, if that amount corresponds to the value received by the customer. Since customers are billed tariff rates, there is no variable consideration in transaction price.

Unbilled revenue is included in residential and commercial revenues above. Natural gas consumption is estimated for the period subsequent to the last billed date and up through the last day of the month. Estimated volumes and approved tariff rates are utilized to calculate unbilled revenue. The following month, the unbilled estimate is reversed, the actual usage is billed and a new unbilled estimate is calculated. The Company obtains metered usage for industrial customers at the end of each month, thereby eliminating any unbilled consideration for these rate classes.

Other revenues

Other revenues primarily consist of miscellaneous fees and charges and utility-related revenues not directly billed to utility customers, as well as billings for non utility activities. Non utility (unregulated) activities provided by the Company include contract paving and other similar services. Regarding these activities, the customer is invoiced monthly based on services provided. The Company utilizes the practical expedient allowing revenue to be recognized based on invoiced amounts. The transaction price is based on a contractually predetermined rate schedule; therefore, the transaction price represents total value to the customer and no variable price consideration exists.

Alternative Revenue Program (ARP) revenues

ARPs, which fall outside the scope of ASC 606, are SCC approved mechanisms that allow for the adjustment of revenues for certain broad, external factors, or for additional billings if the entity achieves certain performance targets. The Company's ARPs include its Weather Normalization Adjustment (WNA), which adjusts revenues for the effects of weather temperature variations from the 30-year average, and the SAVE ("Steps to Advance Virginia's Energy") Plan over/under collection mechanism, which adjusts revenues for the differences between SAVE Plan revenues billed to customers in the current tariff rates and the revenue earned, as calculated based on the timing and extent of infrastructure replacement completed during the period. These amounts are ultimately collected from, or returned to, customers through future changes to tariff rates.

Customer Accounts Receivable

Accounts receivable, as reflected in the Condensed Consolidated Balance Sheets, includes both billed and unbilled customer revenues, as well as amounts that are not related to customers. The balances of customer receivables are provided below:

	Assets (current)				Liabilities (current)
	Trade accounts receivable (1)		Unbilled revenue (1)		Customer credit balances			Customer deposits
Balance at September 30, 2018	$	2,675,611	$	913,087	$	1,003,622		$	1,421,043
Balance at March 31, 2019	9,001,334		2,796,670		459,840			1,560,403
Increase (decrease)	$	6,325,723	$	1,883,583	$	(543,782	)	$	139,360
(1) Included in "Accounts receivable, net" in the condensed consolidated balance sheet. Amounts shown net of reserve for bad debts.

The Company had no significant contract assets or liabilities during the period. Furthermore, the Company did not incur any significant costs to obtain contracts.

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Income Taxes

6 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act, ("TCJA") became law. The TCJA's most significant impact was the reduction of the maximum corporate federal income tax rate from 35% to 21% beginning January 1, 2018. As the Company is a fiscal year taxpayer, it had a blended rate of 24.3% in fiscal 2018 and fully transitioned to the 21%, rate in fiscal 2019.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be revalued to reflect the reduction in the federal tax rate. For unregulated entities, the revaluation of excess deferred income taxes are flowed through income tax expense in the period of change. For rate regulated entities such as Roanoke Gas, these excess deferred taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. As a result, these net excess deferred taxes must be returned to customers. The Company began reflecting the refund of these excess deferred taxes in late fiscal 2018. As the refund should have no effect on the income of the Company, the income statement reflects both a reduction in revenues and a corresponding reduction in income taxes associated with the flow back of these net excess deferred taxes. The result is a lowering of the effective tax rate for the Company.

A reconciliation of income tax expense from applying the federal statutory rates in effect for each period to total income tax expense is presented below:

	Three Months Ended March 31,						Six Months Ended March 31,
	2019			2018			2019			2018
Income before income taxes	$	6,130,718		$	4,876,360		$	9,267,093		$	8,071,518
Corporate federal tax rate	21.00		%	24.30		%	21.00		%	24.30		%
Income tax expense computed at the federal statutory rate	$	1,287,451		$	1,184,955		$	1,946,090		$	1,961,379
State income taxes, net of federal tax benefit	290,481			222,127			441,070			368,214
Net amortization of excess deferred taxes on regulated operations	(86,208		)	—			(172,417		)	—
Revaluation of unregulated deferred taxes	—			—			—			206,830
Other, net	(31,096		)	3,349			(51,902		)	9,704
Total income tax expense	$	1,460,628		$	1,410,431		$	2,162,841		$	2,546,127
Effective tax rate	23.8		%	28.9		%	23.3		%	31.5		%

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Rates and Regulatory Matters

6 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Rates and Regulatory Matters

Rates and Regulatory Matters

The 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.

As referenced in Note 3, the TCJA reduced the federal corporate tax rate to 21%. The Company revalued its deferred tax assets and liabilities to reflect the new federal tax rate. Under the provisions of ASC 740, the corresponding adjustment to deferred income taxes generally flows directly to income tax expense. For rate regulated entities such as Roanoke Gas, these excess deferred taxes were originally recovered from its customers based on billing rates derived using a federal income tax rate of 34%. Therefore, the adjustment to the net deferred tax liabilities of Roanoke Gas, to the extent such net deferred tax liabilities are attributable to rate base or cost of service for customers, are refundable to customers. Roanoke Gas began accounting for the refund of these excess deferred taxes in fiscal 2018 along with reflecting a corresponding reduction in income tax expense. As of March 31, 2019, Roanoke Gas had approximately $11,200,000 remaining in both the current and non-current portions of the net regulatory liability related to these excess deferred income taxes, most of which will be refunded over a 28 year period per IRS normalization requirements. The provision for excess deferred taxes included in regulatory liabilities are subject to SCC review and adjustment as part of their audit of the general rate application.

The Company has transitioned to a corporate federal income tax rate of 21% and a combined 25.74% state and federal tax rate in fiscal 2019. In January 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, currently included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. For the six-month periods ending March 31, 2019 and 2018, the Company had recorded a reduction to revenue of $523,881 and $821,343, respectively, reflecting the estimated excess revenue collected from customers. Effective with January 2019 customer billings, the Company began refunding the excess revenues to customers. The estimated total refund of these excess revenues is subject to final review and adjustment by the SCC as part of their review of the general rate application.

On October 10, 2018, Roanoke Gas filed a general rate application requesting an annual increase in customer non-gas base rates of $10.5 million. This application incorporates into the non-gas base rates the impact of tax reform, non-SAVE utility plant investment, increased operating costs and approximately $4.7 million in SAVE plan revenues that were previously billed through the SAVE rider. The new non-gas base rates were placed in effect for service rendered on or after January 1, 2019, subject to refund pending audit and final order by the SCC. SCC staff is currently auditing the rate application and their report is not due until later in the Company's fiscal third quarter. The Company has recorded a provision for refund, including interest associated with customer billings, under the new rates. As the SCC audit is still in progress, the Company based its estimated refund on the history of the percentage of additional revenues realized from past rate applications. The amount of the refund is an estimate, and the final order could result in lower or higher revenues than currently reflected in the financial statements. The Company will refine its estimates as more information becomes available.

The current portion of the excess deferred income tax, the accrued refund for excess revenues due to tax rate change and the estimated refund related to the non-gas rates placed into effect on January 1, 2019 are included in the regulatory liabilities line in the Condensed Consolidated Balance Sheet.

The SCC requires regulated entities within the state to perform a depreciation study every 5 years. The Company completed its last depreciation study in June 2014 and is currently in the process of preparing the current depreciation study for filing in June 2019. The new depreciation rates are effective retroactive to October 1, 2018 and will be implemented once approved by the SCC. Any adjustment to depreciation expense as a result of the study is expected to be reflected in the results of the quarter ended September 30, 2019.

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Other Investments

6 Months Ended

Mar. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Other Investments

Other Investments

In October 2015, the Company, through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), acquired a 1% equity interest in the Mountain Valley Pipeline, LLC (the “LLC”).

The LLC was established to construct and operate the Mountain Valley Pipeline ("MVP" or "pipeline"), a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. When completed, the pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day. The pipeline has received Federal Energy Regulatory Commission ("FERC") approval and is under construction.

The current total project cost as estimated by the LLC managing partner is $4.6 billion. Midstream's estimated total cash contribution for its 1% equity interest in the LLC will be approximately $46 million provided through periodic capital contributions made throughout the term of the project. The Company is utilizing the equity method to account for the transactions and activity of the investment in MVP and is participating in the earnings in proportion to its level of investment.

In April 2018, the LLC announced the MVP Southgate project ("Southgate"), which is a 70 mile pipeline extending from the MVP mainline in Virginia to delivery points in North Carolina. Midstream is a less than 1% investor in the project, which will be accounted for under the cost method. Total estimated project cost is between $350 and $500 million, of which Midstream's portion estimated to be between $1.8 to $2.5 million.

On a quarterly basis, the LLC issues a capital call notice, which specifies the capital contributions for MVP and Southgate to be paid over the subsequent 3 months. As of March 31, 2019, the Company had $3,346,681 remaining to be paid under the most recent notice. The capital contribution payable has been reflected on the Company's Balance Sheet as of March 31, 2019, with a corresponding increase to "investment in unconsolidated affiliates". Related to capital contributions payable, there was a $6,796,085 non-cash decrease in the "investment in unconsolidated affiliates" during the six months ended March 31, 2019. Funding for Midstream's investments in the LLC for both the MVP and Southgate projects are being provided through two unsecured promissory notes, each with a 5-year term as discussed further in Note 7.

The financial statement locations of the investment in the LLC are as follows:

Balance Sheet Location of Other Investments:	March 31, 2019		September 30, 2018
Other Assets:
Investment in MVP	$	36,065,841	$	28,387,031
Investment in Southgate	210,707		120,115
Investment in unconsolidated affiliates	$	36,276,548	$	28,507,146

Current Liabilities:
MVP	$	3,275,544	$	10,022,652
Southgate	71,137		120,114
Capital contributions payable	$	3,346,681	$	10,142,766

	Three Months Ended				Six Months Ended
Income Statement Location of Other Investments:	March 31, 2019		March 31, 2018		March 31, 2019		March 31, 2018
Equity in earnings of unconsolidated affiliate	$	698,175	$	191,513	$	1,261,224	$	340,324

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Derivatives and Hedging

6 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Hedging

Derivatives and Hedging

The Company’s risk management 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 risk management policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company seeks to hedge include the price of natural gas and the cost of borrowed funds.

The Company has one interest rate swap associated with its $7,000,000 term note as discussed in Note 7. Effective November 1, 2017, the swap agreement converted the floating rate note based on LIBOR into fixed-rate debt with a 2.30% effective interest rate. The swap qualifies as a cash flow hedge with changes in fair value reported in other comprehensive income. No portion of the swap was deemed ineffective during the periods presented.

The table below reflects the fair values of the derivative instrument and its corresponding classification in the condensed consolidated balance sheet:

	March 31, 2019	September 30, 2018
Derivative designated as hedging instrument:
Current assets:
Interest rate swap	$54,786	$100,723
Other assets:
Interest rate swap	$86,745	$209,840
Total derivatives designed as hedging instruments	$141,531	$310,563

The table in Note 8 reflects the effect on income and other comprehensive income of the Company's cash flow hedge.

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Long-Term Debt

6 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

On January 2, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10 million. These notes, issued on March 28, 2019, will mature 12-years from the date of issue and have a fixed interest rate of 4.41%. Proceeds from these notes were used to refinance a portion of Roanoke Gas' debt under the line-of-credit.

On March 26, 2019, Roanoke Gas entered into a new unsecured line-of-credit agreement. This agreement replaced the prior line-of-credit agreement scheduled to expire March 31, 2020. The new agreement is for a two-year term expiring March 31, 2021 with a maximum borrowing limit of $30,000,000. Amounts drawn against the agreement are considered to be non-current as the balance under the line-of-credit is not subject to repayment within the next 12-month period. The agreement has a variable-interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points and provides multi-tiered borrowing limits associated with the seasonal borrowing demands of the Company. The Company's total available borrowing limits during the term of the agreement range from $3,000,000 to $30,000,000.

On February 19, 2019, Midstream entered into an agreement with the lending institutions to amend its existing credit agreement and related notes. The amendment increased total borrowing limits to $50 million through the date of maturity to meet the projected funding requirements for completion of the MVP. With the exception of the increase in borrowing limits, all remaining terms under the notes remain unchanged including the variable-interest rate based on 30-day LIBOR plus 135 basis points.

Roanoke Gas also has other unsecured notes at varying fixed interest rates as well as a variable-rate note with interest based on 30-day LIBOR plus 90 basis points. The variable rate note is hedged by a swap agreement, which converts the debt into a fixed-rate instrument with an annual interest rate of 2.30%.

All of the debt agreements set forth certain representations, warranties and covenants to which the Company is subject, including financial covenants that limit consolidated long-term indebtedness to not more than 65% of total capitalization. All of the debt agreements, except for the line-of-credit, provide for priority indebtedness to not exceed 15% of consolidated total assets.

Long-term debt consists of the following:

	March 31, 2019				September 30, 2018
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Roanoke Gas Company:
Unsecured senior notes payable, at 4.26% due on September 18, 2034	$	30,500,000	$	149,638	$	30,500,000	$	154,465
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		8,615		7,000,000		10,283
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		40,936		8,000,000		43,343
Unsecured term notes payable, at 4.41% due on March 28, 2031	10,000,000		33,521		—		—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35%, due December 29, 2020	31,722,200		84,525		17,743,200		74,190
Total notes payable	$	87,222,200	$	317,235	$	63,243,200	$	282,281
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2021	$	—	$	—	$	7,361,017	$	—
Total long-term debt	$	87,222,200	$	317,235	$	70,604,217	$	282,281

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Other Comprehensive Income

6 Months Ended

Mar. 31, 2019

Equity [Abstract]

Other Comprehensive Income

Other Comprehensive Income

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

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(40,059	)	$	10,311		$	(29,748	)
Transfer of realized gains to interest expense	(19,355		)	4,982			(14,373		)
Net interest rate swap	(59,414		)	15,293			(44,121		)
Defined benefit plans:
Amortization of actuarial gains	(2,576		)	663			(1,913		)
Other comprehensive loss	$	(61,990	)	$	15,956		$	(46,034	)
Three Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	90,363		$	(26,061	)	$	64,302
Transfer of realized gains to interest expense	(3,554		)	1,025			(2,529		)
Net interest rate swap	86,809			(25,036		)	61,773
Defined benefit plans:
Amortization of actuarial gains	(5,971		)	1,722			(4,249		)
Other comprehensive income	$	80,838		$	(23,314	)	$	57,524

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Six Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(134,015	)	$	34,495		$	(99,520	)
Transfer of realized gains to interest expense	(35,017		)	9,013			(26,004		)
Net interest rate swap	(169,032		)	43,508			(125,524		)
Defined benefit plans:
Amortization of actuarial gains	(5,152		)	1,326			(3,826		)
Other comprehensive loss	$	(174,184	)	$	44,834		$	(129,350	)
Six Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	151,944		$	(43,821	)	$	108,123
Transfer of realized gains to interest expense	(2,396		)	691			(1,705		)
Net interest rate swap	149,548			(43,130		)	106,418
Defined benefit plans:
Amortization of actuarial gains	(11,942		)	3,444			(8,498		)
Other comprehensive income	$	137,606		$	(39,686	)	$	97,920

The amortization of actuarial gains and losses is included as a component of net periodic pension and postretirement benefit costs under other income (expense), net.

Reconciliation of Other Accumulated Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2018	$	(871,668	)
Other comprehensive loss	(129,350		)
Balance at March 31, 2019	$	(1,001,018	)

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Commitments and Contingencies

6 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its service area. The current franchise agreements expire December 31, 2035. The Company's certificates of public convenience and necessity are exclusive and are intended for perpetual duration. 

Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company utilizes an asset manager to assist in optimizing the use of its transportation, storage rights and gas supply in order to provide a secure and reliable source of natural gas to its customers. The Company also has storage and pipeline capacity contracts to store and deliver natural gas to the Company’s distribution system. Roanoke Gas is currently served directly by two primary pipelines. These two pipelines deliver all of the natural gas supplied to the Company’s distribution system. Depending on 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's ability to deliver natural gas to its customers and its results of operations. The MVP will provide Roanoke Gas with access to an additional delivery source to its distribution system, increasing system reliability and the Company's ability to meet future demands for natural gas.

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Earnings Per Share

6 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per common share for the three months and six months ended March 31, 2019 and 2018 were calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share were calculated by dividing net income by the weighted average common shares outstanding during the period plus potential dilutive common shares. A reconciliation of basic and diluted earnings per share is presented below:

	Three Months Ended March 31,				Six Months Ended March 31,
	2019		2018		2019		2018
Net Income	$	4,670,090	$	3,465,929	$	7,104,252	$	5,525,391
Weighted average common shares	8,032,218		7,371,694		8,017,820		7,309,215
Effect of dilutive securities:
Options to purchase common stock	40,931		41,657		44,600		45,018
Diluted average common shares	8,073,149		7,413,351		8,062,420		7,354,233
Earnings Per Share of Common Stock:
Basic	$	0.58	$	0.47	$	0.89	$	0.76
Diluted	$	0.58	$	0.47	$	0.88	$	0.75

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Employee Benefit Plans

6 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Employee Benefit Plans

Employee Benefit Plans

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 hired before January 1, 2017 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 is detailed as follows:

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of net periodic pension cost:
Service cost	$	134,317		$	166,309		$	268,634		$	332,618
Interest cost	291,682			272,045			583,364			544,090
Expected return on plan assets	(387,359		)	(465,710		)	(774,718		)	(931,420		)
Recognized loss	39,650			87,758			79,300			175,516
Net periodic pension cost	$	78,290		$	60,402		$	156,580		$	120,804

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of postretirement benefit cost:
Service cost	$	33,221		$	41,805		$	66,442		$	83,610
Interest cost	162,236			160,151			324,472			320,302
Expected return on plan assets	(136,805		)	(155,845		)	(273,610		)	(311,690		)
Recognized loss	30,951			70,967			61,902			141,934
Net postretirement benefit cost	$	89,603		$	117,078		$	179,206		$	234,156

The components of net periodic benefit cost, other than the service cost component, are included in the line item "other income (expense), net" in the condensed consolidated income statement as prescribed under ASU 2017-07 and discussed in Note 1. Service cost is included in the "operations and maintenance" line.

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.

	Fiscal Year-to-Date Contributions		Remaining Fiscal Year Contributions
Defined benefit pension plan	$	400,000	$	400,000
Postretirement medical plan	—		300,000
Total	$	400,000	$	700,000

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Fair Value Measurements

6 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

FASB ASC No. 820, Fair Value Measurements and Disclosures, established a fair value hierarchy that prioritizes each input to the valuation method used to measure fair value of financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis into one of the following three 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 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 following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as required by existing guidance and the fair value measurements by level within the fair value hierarchy as of March 31, 2019 and September 30, 2018:

			Fair Value Measurements - March 31, 2019
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	141,531	$	—	$	141,531	$	—
Total	$	141,531	$	—	$	141,531	$	—
Liabilities:
Natural gas purchases	$	430,759	$	—	$	430,759	$	—
Total	$	430,759	$	—	$	430,759	$	—
			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

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.

Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on weighted average first of the month index prices corresponding to the month of the scheduled payment. At March 31, 2019 and September 30, 2018, the Company had recorded in accounts payable the estimated fair value of the liability valued at the corresponding first of month index prices for which the liability is expected to be settled.

The Company’s nonfinancial assets and liabilities measured at fair value on a nonrecurring basis consist of its asset retirement obligations. The asset retirement obligations are measured at fair value at initial recognition based on expected future cash flows required to settle the obligation.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments. In addition, the carrying amount of the variable rate line-of-credit is a reasonable approximation of its fair value. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of March 31, 2019 and September 30, 2018:

			Fair Value Measurements - March 31, 2019
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	87,222,200	$	—	$	—	$	88,286,143
Total	$	87,222,200	$	—	$	—	$	88,286,143
			Fair Value Measurements - September 30, 2018
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

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 spreads.

FASB ASC 825, Financial Instruments, requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. As of March 31, 2019 and September 30, 2018, no single customer accounted for more than 5% of the total accounts receivable balance. The Company maintains certain credit standards with its customers and requires a customer deposit if such evaluation warrants.

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Subsequent Events

6 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were issued. There were no items not otherwise disclosed above which would have materially impacted the Company’s condensed consolidated financial statements.

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Basis of Presentation (Policies)

6 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

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.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly Resources' financial position as of March 31, 2019 and the results of its operations, cash flows, comprehensive income and changes in stockholders' equity for the three and six months ended March 31, 2019 and 2018. The results of operations for the three and six months ended March 31, 2019 are not indicative of the results to be expected for the fiscal year ending September 30, 2019 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The unaudited condensed consolidated interim financial statements and condensed notes are presented as permitted under the rules and regulations of the Securities and Exchange Commission. Pursuant to those rules, certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures are adequate to make the information not misleading. Therefore, the condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K for the year ended September 30, 2018. The September 30, 2018 balance sheet was included in the Company’s audited financial statements included in Form 10-K.

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.

The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements in Form 10-K for the year ended September 30, 2018. Newly adopted and newly issued accounting standards are discussed below.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This reclassification does not change net income and makes the Company's income statement presentation consistent with industry peers.

Recently Issued or Adopted Accounting Standards

Recently Issued or 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 standard is effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period.

The Company adopted ASU 2014-09 and all amendments beginning in the quarter ended December 31, 2018. 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 further information.

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 beginning with the quarter ended December 31, 2018. The new guidance did not have a material effect on the Company's financial position, results of operations or cash flows.

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. In addition, the new guidance includes quantitative and qualitative disclosure requirements to aid financial statement users in better understanding the amount, timing and uncertainty of cash flows arising from leases. 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. In January 2018, the FASB issued ASU 2018-01, which provides a practical expedient that allows entities the option of not evaluating existing land easements under the new lease standard for those easements that were entered into prior to adoption. New or modified land easements will require evaluation on a prospective basis. The Company has completed its inventory of leases and does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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. The Company adopted the new guidance effective October 1, 2018. As a result, the Company now presents the other components of net periodic benefit costs outside of operations under the category of "other income (expense), net" in the condensed consolidated income statement. As the new guidance related to the expense classification was implemented on a retrospective basis, adjustments were made to the prior period financial statements as follow:

	Three Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	3,458,256		$	30,633		$	3,488,889
Total operating expenses	19,611,255			30,633			19,641,888
Operating income	5,306,718			(30,633		)	5,276,085
Other income (expense), net	11,315			30,633			41,948
Income before income taxes	$	4,876,360		$	—		$	4,876,360
	Six Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	6,655,367		$	61,266		$	6,716,633
Total operating expenses	34,692,182			61,266			34,753,448
Operating income	8,981,842			(61,266		)	8,920,576
Other income (expense), net	(4,817		)	61,266			56,449
Income before income taxes	$	8,071,518		$	—		$	8,071,518

In addition, the ASU allows only the service cost component of net periodic benefit cost to be eligible for capitalization when applicable. Previously, the Company included all components of net periodic benefit costs for capitalization. Management has had discussions with its state regulators regarding the adoption of this ASU for regulatory purposes. The regulatory body has not taken a position on the change in capitalization requirements for these benefit costs and will evaluate the impact of this ASU on a case by case basis. The Company adopted the capitalization change prospectively on October 1, 2018. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits are not appropriate for regulatory purposes, the Company may have to establish regulatory assets or liabilities for those costs or benefits excluded from capitalization under this ASU. The adoption of this new guidance does not have a material effect on the Company's consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting For Hedging Activities. The ASU is meant to simplify recognition and presentation guidance in an effort to improve financial reporting of cash flow and fair value hedging relationships to better portray the economic results of an entity's risk management activities. This is achieved through changes to both the designation and measurement guidance for qualifying hedging relationships, as well as changes to the presentation of hedge results. 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 has not completed its evaluation of the new guidance; however, it does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20) - Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The new guidance is effective for the Company for the annual reporting period ending September 30, 2021. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, the ASU only modifies disclosure requirements and will not effect financial position, results of operations or cash flows.

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU reduces the complexity of accounting for costs of implementing a cloud computing service arrangement and aligns the following requirements to capitalize implementation costs: 1) those incurred in a hosting arrangement that is a service contract, and 2) those incurred to develop or obtain internal-use software, including hosting arrangements that include an internal software license. The new guidance is effective for the Company for the annual reporting period beginning October 1, 2020. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will change the future treatment of certain contracts by allowing related implementation costs to be capitalized and amortized over time, rather than directly expensed. Management does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

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.

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Basis of Presentation (Tables)

6 Months Ended

Mar. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Adjustments to Prior Period Financial Statements

As the new guidance related to the expense classification was implemented on a retrospective basis, adjustments were made to the prior period financial statements as follow:

	Three Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	3,458,256		$	30,633		$	3,488,889
Total operating expenses	19,611,255			30,633			19,641,888
Operating income	5,306,718			(30,633		)	5,276,085
Other income (expense), net	11,315			30,633			41,948
Income before income taxes	$	4,876,360		$	—		$	4,876,360
	Six Months Ended March 31, 2018
	As Previously Reported			Effect of Change			As Adjusted
Operations and maintenance	$	6,655,367		$	61,266		$	6,716,633
Total operating expenses	34,692,182			61,266			34,753,448
Operating income	8,981,842			(61,266		)	8,920,576
Other income (expense), net	(4,817		)	61,266			56,449
Income before income taxes	$	8,071,518		$	—		$	8,071,518

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Revenue (Tables)

6 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables summarize revenue by customer, product and income statement classification:

	Three months ended March 31, 2019								Three months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	15,397,504		$	—	$	15,397,504		$	15,479,644		$	—	$	15,479,644
Commercial	8,357,598			—		8,357,598			8,504,212			—		8,504,212
Industrial and Transportation	1,249,316			—		1,249,316			1,137,874			—		1,137,874
Revenue reductions (TCJA) (1)	—			—		—			(358,901		)	—		(358,901		)
Other	108,418			216,210		324,628			148,505			309,397		457,902
Total contracts with customers	25,112,836			216,210		25,329,046			24,911,334			309,397		25,220,731
Alternative Revenue Programs	(54,087		)	—		(54,087		)	(302,758		)	—		(302,758		)
Total operating revenues	$	25,058,749		$	216,210	$	25,274,959		$	24,608,576		$	309,397	$	24,917,973
	Six months ended March 31, 2019								Six months ended March 31, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	28,410,332		$	—	$	28,410,332		$	26,700,554		$	—	$	26,700,554
Commercial	15,700,155			—		15,700,155			14,820,511			—		14,820,511
Industrial and Transportation	2,475,364			—		2,475,364			2,265,677			—		2,265,677
Revenue reductions (TCJA) (1)	(523,881		)	—		(523,881		)	(821,343		)	—		(821,343		)
Other	334,908			396,376		731,284			393,770			545,454		939,224
Total contracts with customers	46,396,878			396,376		46,793,254			43,359,169			545,454		43,904,623
Alternative Revenue Programs	(301,548		)	—		(301,548		)	(230,599		)	—		(230,599		)
Total operating revenues	$	46,095,330		$	396,376	$	46,491,706		$	43,128,570		$	545,454	$	43,674,024
(1) Accrued refund associated with excess revenue collected in tariff rates associated with the reduction in federal income tax rates. See Note 4 for more information.

Schedule of Customer Accounts Receivable

The balances of customer receivables are provided below:

	Assets (current)				Liabilities (current)
	Trade accounts receivable (1)		Unbilled revenue (1)		Customer credit balances			Customer deposits
Balance at September 30, 2018	$	2,675,611	$	913,087	$	1,003,622		$	1,421,043
Balance at March 31, 2019	9,001,334		2,796,670		459,840			1,560,403
Increase (decrease)	$	6,325,723	$	1,883,583	$	(543,782	)	$	139,360
(1) Included in "Accounts receivable, net" in the condensed consolidated balance sheet. Amounts shown net of reserve for bad debts.

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Income Taxes (Tables)

6 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation of income tax expense from applying the federal statutory rates in effect for each period to total income tax expense is presented below:

	Three Months Ended March 31,						Six Months Ended March 31,
	2019			2018			2019			2018
Income before income taxes	$	6,130,718		$	4,876,360		$	9,267,093		$	8,071,518
Corporate federal tax rate	21.00		%	24.30		%	21.00		%	24.30		%
Income tax expense computed at the federal statutory rate	$	1,287,451		$	1,184,955		$	1,946,090		$	1,961,379
State income taxes, net of federal tax benefit	290,481			222,127			441,070			368,214
Net amortization of excess deferred taxes on regulated operations	(86,208		)	—			(172,417		)	—
Revaluation of unregulated deferred taxes	—			—			—			206,830
Other, net	(31,096		)	3,349			(51,902		)	9,704
Total income tax expense	$	1,460,628		$	1,410,431		$	2,162,841		$	2,546,127
Effective tax rate	23.8		%	28.9		%	23.3		%	31.5		%

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Other Investments (Tables)

6 Months Ended

Mar. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Other Investments

The financial statement locations of the investment in the LLC are as follows:

Balance Sheet Location of Other Investments:	March 31, 2019		September 30, 2018
Other Assets:
Investment in MVP	$	36,065,841	$	28,387,031
Investment in Southgate	210,707		120,115
Investment in unconsolidated affiliates	$	36,276,548	$	28,507,146

Current Liabilities:
MVP	$	3,275,544	$	10,022,652
Southgate	71,137		120,114
Capital contributions payable	$	3,346,681	$	10,142,766

	Three Months Ended				Six Months Ended
Income Statement Location of Other Investments:	March 31, 2019		March 31, 2018		March 31, 2019		March 31, 2018
Equity in earnings of unconsolidated affiliate	$	698,175	$	191,513	$	1,261,224	$	340,324

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Derivatives and Hedging (Tables)

6 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Fair Values of Derivative Instrument

The table below reflects the fair values of the derivative instrument and its corresponding classification in the condensed consolidated balance sheet:

	March 31, 2019	September 30, 2018
Derivative designated as hedging instrument:
Current assets:
Interest rate swap	$54,786	$100,723
Other assets:
Interest rate swap	$86,745	$209,840
Total derivatives designed as hedging instruments	$141,531	$310,563

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Long-Term Debt (Tables)

6 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Long-term debt consists of the following:

	March 31, 2019				September 30, 2018
	Principal		Unamortized Debt Issuance Costs		Principal		Unamortized Debt Issuance Costs
Roanoke Gas Company:
Unsecured senior notes payable, at 4.26% due on September 18, 2034	$	30,500,000	$	149,638	$	30,500,000	$	154,465
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		8,615		7,000,000		10,283
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		40,936		8,000,000		43,343
Unsecured term notes payable, at 4.41% due on March 28, 2031	10,000,000		33,521		—		—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35%, due December 29, 2020	31,722,200		84,525		17,743,200		74,190
Total notes payable	$	87,222,200	$	317,235	$	63,243,200	$	282,281
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2021	$	—	$	—	$	7,361,017	$	—
Total long-term debt	$	87,222,200	$	317,235	$	70,604,217	$	282,281

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Other Comprehensive Income (Tables)

6 Months Ended

Mar. 31, 2019

Equity [Abstract]

Summary of Other Comprehensive Income and Loss

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

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(40,059	)	$	10,311		$	(29,748	)
Transfer of realized gains to interest expense	(19,355		)	4,982			(14,373		)
Net interest rate swap	(59,414		)	15,293			(44,121		)
Defined benefit plans:
Amortization of actuarial gains	(2,576		)	663			(1,913		)
Other comprehensive loss	$	(61,990	)	$	15,956		$	(46,034	)
Three Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	90,363		$	(26,061	)	$	64,302
Transfer of realized gains to interest expense	(3,554		)	1,025			(2,529		)
Net interest rate swap	86,809			(25,036		)	61,773
Defined benefit plans:
Amortization of actuarial gains	(5,971		)	1,722			(4,249		)
Other comprehensive income	$	80,838		$	(23,314	)	$	57,524

	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Six Months Ended March 31, 2019
Interest rate swap:
Unrealized losses	$	(134,015	)	$	34,495		$	(99,520	)
Transfer of realized gains to interest expense	(35,017		)	9,013			(26,004		)
Net interest rate swap	(169,032		)	43,508			(125,524		)
Defined benefit plans:
Amortization of actuarial gains	(5,152		)	1,326			(3,826		)
Other comprehensive loss	$	(174,184	)	$	44,834		$	(129,350	)
Six Months Ended March 31, 2018
Interest rate swap:
Unrealized gains	$	151,944		$	(43,821	)	$	108,123
Transfer of realized gains to interest expense	(2,396		)	691			(1,705		)
Net interest rate swap	149,548			(43,130		)	106,418
Defined benefit plans:
Amortization of actuarial gains	(11,942		)	3,444			(8,498		)
Other comprehensive income	$	137,606		$	(39,686	)	$	97,920

Reconciliation of Other Accumulated Other Comprehensive Income (Loss)

Reconciliation of Other Accumulated Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2018	$	(871,668	)
Other comprehensive loss	(129,350		)
Balance at March 31, 2019	$	(1,001,018	)

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Earnings Per Share (Tables)

6 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Schedule of Basic and Diluted Earnings Per Share Reconciliation

A reconciliation of basic and diluted earnings per share is presented below:

	Three Months Ended March 31,				Six Months Ended March 31,
	2019		2018		2019		2018
Net Income	$	4,670,090	$	3,465,929	$	7,104,252	$	5,525,391
Weighted average common shares	8,032,218		7,371,694		8,017,820		7,309,215
Effect of dilutive securities:
Options to purchase common stock	40,931		41,657		44,600		45,018
Diluted average common shares	8,073,149		7,413,351		8,062,420		7,354,233
Earnings Per Share of Common Stock:
Basic	$	0.58	$	0.47	$	0.89	$	0.76
Diluted	$	0.58	$	0.47	$	0.88	$	0.75

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Employee Benefit Plans (Tables)

6 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Schedule of Components of Net Periodic Pension and Postretirement Benefit Cost

Net pension plan and postretirement plan expense is detailed as follows:

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of net periodic pension cost:
Service cost	$	134,317		$	166,309		$	268,634		$	332,618
Interest cost	291,682			272,045			583,364			544,090
Expected return on plan assets	(387,359		)	(465,710		)	(774,718		)	(931,420		)
Recognized loss	39,650			87,758			79,300			175,516
Net periodic pension cost	$	78,290		$	60,402		$	156,580		$	120,804

	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2019			2018			2019			2018
Components of postretirement benefit cost:
Service cost	$	33,221		$	41,805		$	66,442		$	83,610
Interest cost	162,236			160,151			324,472			320,302
Expected return on plan assets	(136,805		)	(155,845		)	(273,610		)	(311,690		)
Recognized loss	30,951			70,967			61,902			141,934
Net postretirement benefit cost	$	89,603		$	117,078		$	179,206		$	234,156

Summary of Employer Contributions to Defined Benefit Plans

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.

	Fiscal Year-to-Date Contributions		Remaining Fiscal Year Contributions
Defined benefit pension plan	$	400,000	$	400,000
Postretirement medical plan	—		300,000
Total	$	400,000	$	700,000

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Fair Value Measurements (Tables)

6 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis

The following table summarizes the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as required by existing guidance and the fair value measurements by level within the fair value hierarchy as of March 31, 2019 and September 30, 2018:

			Fair Value Measurements - March 31, 2019
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	141,531	$	—	$	141,531	$	—
Total	$	141,531	$	—	$	141,531	$	—
Liabilities:
Natural gas purchases	$	430,759	$	—	$	430,759	$	—
Total	$	430,759	$	—	$	430,759	$	—
			Fair Value Measurements - September 30, 2018
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	310,563	$	—	$	310,563	$	—
Total	$	310,563	$	—	$	310,563	$	—
Liabilities:
Natural gas purchases	$	693,495	$	—	$	693,495	$	—
Total	$	693,495	$	—	$	693,495	$	—

Summary of the Fair Value of Financial Assets and Liabilities Not Adjusted to Fair Value

The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of March 31, 2019 and September 30, 2018:

			Fair Value Measurements - March 31, 2019
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	87,222,200	$	—	$	—	$	88,286,143
Total	$	87,222,200	$	—	$	—	$	88,286,143
			Fair Value Measurements - September 30, 2018
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	63,243,200	$	—	$	—	$	62,435,237
Total	$	63,243,200	$	—	$	—	$	62,435,237

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Basis of Presentation (Details) - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance	$ 3,714,084	$ 3,488,889	$ 7,236,083	$ 6,716,633
Total operating expenses	19,071,476	19,641,888	37,024,001	34,753,448
Operating income	6,203,483	5,276,085	9,467,705	8,920,576
Other income (expense), net	121,709	41,948	247,595	56,449
Income before income taxes	$ 6,130,718	4,876,360	$ 9,267,093	8,071,518
As Previously Reported [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance		3,458,256		6,655,367
Total operating expenses		19,611,255		34,692,182
Operating income		5,306,718		8,981,842
Other income (expense), net		11,315		(4,817)
Income before income taxes		4,876,360		8,071,518
Effect of Change [Member] | ASU 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance		30,633		61,266
Total operating expenses		30,633		61,266
Operating income		(30,633)		(61,266)
Other income (expense), net		30,633		61,266
Income before income taxes		$ 0		$ 0

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Revenue (Disaggregation of Revenue) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Total contracts with customers	$ 25,329,046	$ 25,220,731	$ 46,793,254	$ 43,904,623
Revenue reductions (TCJA)	0	(358,901)	(523,881)	(821,343)
Alternative Revenue Programs	(54,087)	(302,758)	(301,548)	(230,599)
Operating revenues	25,274,959	24,917,973	46,491,706	43,674,024
Natural Gas [Member] | Residential [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	15,397,504	15,479,644	28,410,332	26,700,554
Natural Gas [Member] | Commercial [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	8,357,598	8,504,212	15,700,155	14,820,511
Natural Gas [Member] | Industrial and Transportation [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	1,249,316	1,137,874	2,475,364	2,265,677
Other [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	324,628	457,902	731,284	939,224
Gas Utility [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	25,112,836	24,911,334	46,396,878	43,359,169
Revenue reductions (TCJA)	0	(358,901)	(523,881)	(821,343)
Alternative Revenue Programs	(54,087)	(302,758)	(301,548)	(230,599)
Operating revenues	25,058,749	24,608,576	46,095,330	43,128,570
Gas Utility [Member] | Natural Gas [Member] | Residential [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	15,397,504	15,479,644	28,410,332	26,700,554
Gas Utility [Member] | Natural Gas [Member] | Commercial [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	8,357,598	8,504,212	15,700,155	14,820,511
Gas Utility [Member] | Natural Gas [Member] | Industrial and Transportation [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	1,249,316	1,137,874	2,475,364	2,265,677
Gas Utility [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	108,418	148,505	334,908	393,770
Non Utility [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	216,210	309,397	396,376	545,454
Revenue reductions (TCJA)	0	0	0	0
Alternative Revenue Programs	0	0	0	0
Operating revenues	216,210	309,397	396,376	545,454
Non Utility [Member] | Natural Gas [Member] | Residential [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	0	0	0	0
Non Utility [Member] | Natural Gas [Member] | Commercial [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	0	0	0	0
Non Utility [Member] | Natural Gas [Member] | Industrial and Transportation [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	0	0	0	0
Non Utility [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Total contracts with customers	$ 216,210	$ 309,397	$ 396,376	$ 545,454

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Revenue (Customer Accounts Receivable) (Details) - USD ($)	6 Months Ended
	Mar. 31, 2019	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Unbilled revenue	$ 2,796,670	$ 913,087
Increase (decrease) in Unbilled revenue	1,883,583
Customer credit balances	459,840	1,003,622
Increase (decrease) in Customer credit balances	(543,782)
Customer deposits	1,560,403	1,421,043
Increase (decrease) in Customer deposits	139,360
Capitalized Contract Cost [Line Items]
Trade accounts receivable	11,872,956	3,913,830
Trade Accounts Receivable [Member]
Capitalized Contract Cost [Line Items]
Trade accounts receivable	9,001,334	$ 2,675,611
Increase (decrease) in Trade accounts receivable	$ 6,325,723

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Income Taxes (Narrative) (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Blended tax rate	21.00%	24.30%	21.00%	24.30%	24.30%

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Income Taxes (Reconciliation of Income Tax Expense Based on Federal Statutory Rate) (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income before income taxes	$ 6,130,718	$ 4,876,360	$ 9,267,093	$ 8,071,518
Corporate federal tax rate	21.00%	24.30%	21.00%	24.30%	24.30%
Income tax expense computed at the federal statutory rate	$ 1,287,451	$ 1,184,955	$ 1,946,090	$ 1,961,379
State income taxes, net of federal tax benefit	290,481	222,127	441,070	368,214
Net amortization of excess deferred taxes on regulated operations	(86,208)	0	(172,417)	0
Revaluation of unregulated deferred taxes	0	0	0	206,830
Other, net	(31,096)	3,349	(51,902)	9,704
Total income tax expense	$ 1,460,628	$ 1,410,431	$ 2,162,841	$ 2,546,127
Effective tax rate	23.80%	28.90%	23.30%	31.50%

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Rates and Regulatory Matters (Details) - USD ($)		6 Months Ended
	Oct. 10, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Regulatory Liabilities [Line Items]
Reduction in deferred tax liability resulting from the Tax Act		$ 10,712,735		$ 11,447,736
Combined state and federal rate		25.74%
Regulatory utility assets provision, period		5 years
Roanoke Gas Company [Member]
Regulatory Liabilities [Line Items]
Reduction in deferred tax liability resulting from the Tax Act		$ 11,200,000
Regulatory liability, refund period (in years)		28 years
Customer refund liability, increase		$ 523,881	$ 821,343
Roanoke Gas Company [Member] | General Rate Case [Member] | Virginia State Corporate Commission (SCC) [Member]
Regulatory Liabilities [Line Items]
Requested non-gas rates increase	$ 10,500,000
SAVE Program component of requested non-gas rates increase (in dollars)	$ 4,700,000

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Other Investments (Narrative) (Details) Bcf in Millions	1 Months Ended		6 Months Ended
	Apr. 30, 2018 USD ($) mi	Oct. 31, 2015 USD ($) debt_instrument Bcf	Mar. 31, 2019 USD ($)	Sep. 30, 2018 USD ($)
Investment [Line Items]
Capital contributions payable term			3 months
Capital contributions payable			$ 3,346,681	$ 10,142,766
Non-cash change in investment in unconsolidated affiliates			(6,796,085)
MVP [Member]
Investment [Line Items]
Capital contributions payable			3,275,544	10,022,652
Southgate [Member]
Investment [Line Items]
Capital contributions payable			$ 71,137	$ 120,114
Midstream [Member]
Investment [Line Items]
Number of unsecured Promissory Notes funding the investment | debt_instrument		2
Debt term		5 years
Midstream [Member] | MVP [Member]
Investment [Line Items]
Equity interest percentage		1.00%
Pipeline capacity per day (in bcf) | Bcf		2
Total project cost		$ 4,600,000,000
Total estimated investment		$ 46,000,000
Midstream [Member] | Southgate [Member]
Investment [Line Items]
Length of planned natural gas pipeline (in miles) | mi	70
Ownership percentage (less than)	1.00%
Midstream [Member] | Southgate [Member] | Minimum [Member]
Investment [Line Items]
Estimated total MVP Southgate pipeline cost projection	$ 350,000,000
Estimated investment in MVP Southgate	1,800,000
Midstream [Member] | Southgate [Member] | Maximum [Member]
Investment [Line Items]
Estimated total MVP Southgate pipeline cost projection	500,000,000
Estimated investment in MVP Southgate	$ 2,500,000

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Other Investments (Schedule of Other Investments) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Other Assets:
Investment in unconsolidated affiliates	$ 36,276,548		$ 36,276,548		$ 28,507,146
Current Liabilities:
Capital contributions payable	3,346,681		3,346,681		10,142,766
Income Statement Location of Other Investments:
Equity in earnings of unconsolidated affiliate	698,175	$ 191,513	1,261,224	$ 340,324
MVP [Member]
Other Assets:
Investment in MVP	36,065,841		36,065,841		28,387,031
Current Liabilities:
Capital contributions payable	3,275,544		3,275,544		10,022,652
Southgate [Member]
Other Assets:
Investment in Southgate	210,707		210,707		120,115
Current Liabilities:
Capital contributions payable	$ 71,137		$ 71,137		$ 120,114

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Derivatives and Hedging (Narrative) (Details)	Mar. 31, 2019 USD ($) instrument_held
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of interest rate swap associated with the term note | instrument_held	1
Roanoke Gas Company [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt instrument, borrowing amount | $	$ 7,000,000
Effective interest rate	2.30%

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Derivatives and Hedging (Schedule of Fair Value of Marked-to-Market Transactions) (Details) - USD ($)	Mar. 31, 2019	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest rate swap, current assets	$ 54,786	$ 100,723
Interest rate swap, other assets	86,745	209,840
Total derivatives designated as hedging instruments	$ 141,531	$ 310,563

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Long-Term Debt (Narrative) (Details) - USD ($)				1 Months Ended	6 Months Ended
	Mar. 28, 2019	Mar. 26, 2019	Feb. 19, 2019	Oct. 31, 2015	Mar. 31, 2019
Debt Instrument [Line Items]
Maximum percentage of Consolidated Long Term Indebtedness to Consolidated Total Capitalization					65.00%
Roanoke Gas [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 4.41%, due March 28, 2031 [Member]
Debt Instrument [Line Items]
Debt instrument, borrowing amount	$ 10,000,000
Debt term	12 years
Stated percentage rate	4.41%				4.41%
Maximum percentage of Priority Indebtedness to Consolidated Total Assets					15.00%
Roanoke Gas [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, borrowing amount					$ 7,000,000
Effective interest rate					2.30%
Maximum percentage of Priority Indebtedness to Consolidated Total Assets					15.00%
Roanoke Gas [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)					0.90%
Roanoke Gas [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 3.58%, due October 2, 2027 [Member]
Debt Instrument [Line Items]
Stated percentage rate					3.58%
Roanoke Gas [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member]
Debt Instrument [Line Items]
Debt term		2 years
Availability fee (as a percent)		0.15%
Roanoke Gas [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)		1.00%			1.00%
Roanoke Gas [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing limit		$ 30,000,000
Roanoke Gas [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing limit		$ 3,000,000
Midstream [Member]
Debt Instrument [Line Items]
Debt term				5 years
Midstream [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 1.35%, due December 29, 2020 [Member]
Debt Instrument [Line Items]
Maximum percentage of Priority Indebtedness to Consolidated Total Assets					15.00%
Midstream [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 1.35%, due December 29, 2020 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)			1.35%		1.35%
Midstream [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 1.35%, due December 29, 2020 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, borrowing amount			$ 50,000,000

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Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($)			6 Months Ended
	Mar. 26, 2019	Feb. 19, 2019	Mar. 31, 2019	Mar. 28, 2019	Sep. 30, 2018
Debt Instrument [Line Items]
Notes payable			$ 87,222,200		$ 63,243,200
Principal			87,222,200		70,604,217
Unamortized Debt Issuance Costs			317,235		282,281
Notes Payable [Member]
Debt Instrument [Line Items]
Notes payable			87,222,200		63,243,200
Unamortized Debt Issuance Costs			317,235		282,281
Roanoke Gas Company [Member] | Unsecured Senior Notes [Member] | Unsecured Senior Notes Payable, at 4.26%, due on September 18, 2034 [Member]
Debt Instrument [Line Items]
Notes payable			30,500,000		30,500,000
Unamortized Debt Issuance Costs			$ 149,638		154,465
Stated percentage rate			4.26%
Roanoke Gas Company [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 [Member]
Debt Instrument [Line Items]
Notes payable			$ 7,000,000		7,000,000
Unamortized Debt Issuance Costs			$ 8,615		10,283
Roanoke Gas Company [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)			0.90%
Roanoke Gas Company [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 3.58%, due October 2, 2027 [Member]
Debt Instrument [Line Items]
Notes payable			$ 8,000,000		8,000,000
Unamortized Debt Issuance Costs			$ 40,936		43,343
Stated percentage rate			3.58%
Roanoke Gas Company [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 4.41%, due March 28, 2031 [Member]
Debt Instrument [Line Items]
Notes payable			$ 10,000,000		0
Unamortized Debt Issuance Costs			$ 33,521		0
Stated percentage rate			4.41%	4.41%
Roanoke Gas Company [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member]
Debt Instrument [Line Items]
Line-of-credit			$ 0		7,361,017
Unamortized Debt Issuance Costs			$ 0		0
Roanoke Gas Company [Member] | Line of Credit [Member] | Line of Credit, at 30-day LIBOR plus 1.00%, due March 31, 2021 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)	1.00%		1.00%
RGC Midstream LLC [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 1.35%, due December 29, 2020 [Member]
Debt Instrument [Line Items]
Notes payable			$ 31,722,200		17,743,200
Unamortized Debt Issuance Costs			$ 84,525		$ 74,190
RGC Midstream LLC [Member] | Unsecured Term Notes [Member] | Unsecured Term Notes Payable, at 30-day LIBOR plus 1.35%, due December 29, 2020 [Member] | 30-day LIBOR [Member]
Debt Instrument [Line Items]
Variable rate basis points (as a percent)		1.35%	1.35%

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Other Comprehensive Income (Schedule of Other Comprehensive Income and Loss) (Details) - USD ($)	3 Months Ended				6 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Mar. 31, 2018
Before-Tax Amount
Other comprehensive loss	$ (61,990)		$ 80,838		$ (174,184)	$ 137,606
Tax (Expense) or Benefit
Other comprehensive loss	15,956		(23,314)		44,834	(39,686)
Net-of-Tax Amount
Other comprehensive loss	(46,034)	$ (83,316)	57,524	$ 40,396	(129,350)	97,920
Interest rate swap [Member]
Before-Tax Amount
Other comprehensive income before reclassifications	(40,059)		90,363		(134,015)	151,944
Reclassifications from accumulated other comprehensive income	(19,355)		(3,554)		(35,017)	(2,396)
Other comprehensive loss	(59,414)		86,809		(169,032)	149,548
Tax (Expense) or Benefit
Other comprehensive income before reclassifications	10,311		(26,061)		34,495	(43,821)
Reclassifications from accumulated other comprehensive income	4,982		1,025		9,013	691
Other comprehensive loss	15,293		(25,036)		43,508	(43,130)
Net-of-Tax Amount
Other comprehensive income before reclassifications	(29,748)		64,302		(99,520)	108,123
Reclassifications from accumulated other comprehensive income	(14,373)		(2,529)		(26,004)	(1,705)
Other comprehensive loss	(44,121)		61,773		(125,524)	106,418
Defined benefit plans [Member]
Before-Tax Amount
Other comprehensive loss	(2,576)		(5,971)		(5,152)	(11,942)
Tax (Expense) or Benefit
Other comprehensive loss	663		1,722		1,326	3,444
Net-of-Tax Amount
Other comprehensive loss	$ (1,913)		$ (4,249)		$ (3,826)	$ (8,498)

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Other Comprehensive Income (Reconciliation of Accumulated Comprehensive Income (Loss)) (Details) - USD ($)	3 Months Ended				6 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Mar. 31, 2018
Increase (Decrease) in Other Accumulated Comprehensive Income (Loss) [Roll Forward]
Balance at beginning of period	$ 80,959,740	$ 79,583,112	$ 61,301,035	$ 60,040,472	$ 79,583,112	$ 60,040,472
Other comprehensive loss	(46,034)	(83,316)	57,524	40,396	(129,350)	97,920
Balance at end of period	84,974,517	80,959,740	79,299,226	61,301,035	84,974,517	79,299,226
Accumulated Other Comprehensive Income (Loss)
Increase (Decrease) in Other Accumulated Comprehensive Income (Loss) [Roll Forward]
Balance at beginning of period	(954,984)	(871,668)	(1,161,868)	(1,202,264)	(871,668)	(1,202,264)
Other comprehensive loss	(46,034)	(83,316)	57,524	40,396
Balance at end of period	$ (1,001,018)	$ (954,984)	$ (1,104,344)	$ (1,161,868)	$ (1,001,018)	$ (1,104,344)

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Commitments and Contingencies (Details)	6 Months Ended
	Mar. 31, 2019 pipeline
Commitments and Contingencies Disclosure [Abstract]
Number of pipelines serving Roanoke Gas	2

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Earnings Per Share (Details) - USD ($)	3 Months Ended				6 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Net Income	$ 4,670,090	$ 2,434,162	$ 3,465,929	$ 2,059,462	$ 7,104,252	$ 5,525,391
Weighted average common shares (in shares)	8,032,218		7,371,694		8,017,820	7,309,215
Effect of dilutive securities:
Options to purchase common stock (in shares)	40,931		41,657		44,600	45,018
Diluted average common shares (in shares)	8,073,149		7,413,351		8,062,420	7,354,233
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.58		$ 0.47		$ 0.89	$ 0.76
Diluted (in dollars per share)	$ 0.58		$ 0.47		$ 0.88	$ 0.75

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Employee Benefit Plans (Schedule of Components of Net Periodic Pension and Postretirement Benefit Cost) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Mar. 31, 2019	Mar. 31, 2018
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 134,317	$ 166,309	$ 268,634	$ 332,618
Interest cost	291,682	272,045	583,364	544,090
Expected return on plan assets	(387,359)	(465,710)	(774,718)	(931,420)
Recognized loss	39,650	87,758	79,300	175,516
Net periodic/postretirement pension/benefit cost	78,290	60,402	156,580	120,804
Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	33,221	41,805	66,442	83,610
Interest cost	162,236	160,151	324,472	320,302
Expected return on plan assets	(136,805)	(155,845)	(273,610)	(311,690)
Recognized loss	30,951	70,967	61,902	141,934
Net periodic/postretirement pension/benefit cost	$ 89,603	$ 117,078	$ 179,206	$ 234,156

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Employee Benefit Plans (Schedule of Actual and Expected Employer Contributions) (Details)	6 Months Ended
	Mar. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Fiscal Year-to-Date Contributions	$ 400,000
Remaining Fiscal Year Contributions	700,000
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fiscal Year-to-Date Contributions	400,000
Remaining Fiscal Year Contributions	400,000
Postretirement Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fiscal Year-to-Date Contributions	0
Remaining Fiscal Year Contributions	$ 300,000

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Fair Value Measurements (Schedule of Fair Value of Financial Assets and Liabilities Measured on a Recurring Basis) (Details) - USD ($)	Mar. 31, 2019	Sep. 30, 2018
Assets:
Interest rate swap	$ 141,531	$ 310,563
Liabilities:
Natural gas purchases	430,759	693,495
Interest Rate Swap [Member]
Assets:
Interest rate swap	141,531	310,563
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Interest rate swap	0	0
Liabilities:
Natural gas purchases	0	0
Quoted Prices in Active Markets (Level 1) [Member] | Interest Rate Swap [Member]
Assets:
Interest rate swap	0	0
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Interest rate swap	141,531	310,563
Liabilities:
Natural gas purchases	430,759	693,495
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Swap [Member]
Assets:
Interest rate swap	141,531	310,563
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Interest rate swap	0	0
Liabilities:
Natural gas purchases	0	0
Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Swap [Member]
Assets:
Interest rate swap	$ 0	$ 0

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Fair Value Measurements (Summary of the Fair Value of Financial Assets and Liabilities Not Adjusted to Fair Value) (Details) - USD ($)	Mar. 31, 2019	Sep. 30, 2018
Quoted Prices in Active Markets (Level 1) [Member]
Liabilities:
Notes payable	$ 0	$ 0
Total	0	0
Significant Other Observable Inputs (Level 2) [Member]
Liabilities:
Notes payable	0	0
Total	0	0
Significant Unobservable Inputs (Level 3) [Member]
Liabilities:
Notes payable	88,286,143	62,435,237
Total	88,286,143	62,435,237
Carrying Value [Member]
Liabilities:
Notes payable	87,222,200	63,243,200
Total	$ 87,222,200	$ 63,243,200