RGC RESOURCES INC - Quarter Report: 2019 June (Form 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 June 30, 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 July 31, 2019
Common Stock, $5 Par Value		8,065,088

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	Unaudited
	June 30, 2019			September 30, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,238,345		$	247,411
Accounts receivable (less allowance for uncollectibles of $417,058 and $103,573, respectively)	5,307,038			3,913,830
Materials and supplies	1,077,945			913,889
Gas in storage	4,147,399			7,627,196
Prepaid income taxes	—			837,683
Under-recovery of gas costs	—			922,898
Interest rate swap	15,886			100,723
Other	1,469,807			980,972
Total current assets	13,256,420			15,544,602
UTILITY PROPERTY:
In service	232,155,352			224,854,320
Accumulated depreciation and amortization	(66,732,043		)	(63,099,306		)
In service, net	165,423,309			161,755,014
Construction work in progress	12,393,021			4,208,614
Utility plant, net	177,816,330			165,963,628
OTHER ASSETS:
Regulatory assets	8,690,501			8,862,147
Investment in unconsolidated affiliates	44,181,429			28,507,146
Interest rate swap	21,181			209,840
Other	457,177			472,743
Total other assets	53,350,288			38,051,876
TOTAL ASSETS	$	244,423,038		$	219,560,106

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	Unaudited
	June 30, 2019			September 30, 2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Dividends payable	$	1,337,968		$	1,242,753
Accounts payable	3,863,902			5,211,032
Capital contributions payable	7,127,688			10,142,766
Customer credit balances	599,736			1,003,622
Income taxes payable	259,420			—
Customer deposits	1,456,665			1,421,043
Accrued expenses	3,399,488			3,750,466
Over-recovery of gas costs	2,156,936			—
Interest rate swap	82,832			—
Regulatory liability	3,261,849			1,320,167
Total current liabilities	23,546,484			24,091,849
LONG-TERM DEBT:
Notes payable	90,802,200			63,243,200
Line-of-credit	—			7,361,017
Less unamortized debt issuance costs	(331,394		)	(282,281		)
Long-term debt net of unamortized debt issuance costs	90,470,806			70,321,936
DEFERRED CREDITS AND OTHER LIABILITIES:
Interest rate swap	429,320			—
Asset retirement obligations	6,647,768			6,417,948
Regulatory cost of retirement obligations	11,966,830			11,163,981
Benefit plan liabilities	3,839,849			3,947,967
Deferred income taxes	12,090,658			12,585,577
Regulatory liability - deferred income taxes	10,694,388			11,447,736
Total deferred credits and other liabilities	45,668,813			45,563,209
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 8,063,957 and 7,994,615, respectively	40,319,785			39,973,075
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	14,179,376			13,043,656
Retained earnings	31,698,604			27,438,049
Accumulated other comprehensive loss	(1,460,830		)	(871,668		)
Total stockholders’ equity	84,736,935			79,583,112
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	244,423,038		$	219,560,106

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2019 AND 2018

UNAUDITED



	Three Months Ended June 30,					Nine Months Ended June 30,
	2019			2018		2019		2018
OPERATING REVENUES:
Gas utility	$	11,534,948		$	11,546,797	$	57,630,278	$	54,675,367
Non utility	148,002			342,773		544,378		888,227
Total operating revenues	11,682,950			11,889,570		58,174,656		55,563,594
OPERATING EXPENSES:
Cost of gas - utility	4,132,871			4,870,683		28,810,668		28,175,366
Cost of sales - non utility	85,872			176,728		320,818		465,925
Operations and maintenance	3,426,717			2,813,549		10,662,800		9,530,182
General taxes	494,958			458,142		1,559,183		1,431,321
Depreciation and amortization	1,905,475			1,734,878		5,716,425		5,204,634
Total operating expenses	10,045,893			10,053,980		47,069,894		44,807,428
OPERATING INCOME	1,637,057			1,835,590		11,104,762		10,756,166
Equity in earnings of unconsolidated affiliate	777,193			245,075		2,038,417		585,399
Other income (expense), net	(5,967		)	36,857		241,628		93,306
Interest expense	925,698			583,592		2,635,129		1,829,423
INCOME BEFORE INCOME TAXES	1,482,585			1,533,930		10,749,678		9,605,448
INCOME TAX EXPENSE	344,030			446,575		2,506,871		2,992,702
NET INCOME	$	1,138,555		$	1,087,355	$	8,242,807	$	6,612,746
BASIC EARNINGS PER COMMON SHARE	$	0.14		$	0.14	$	1.03	$	0.88
DILUTED EARNINGS PER COMMON SHARE	$	0.14		$	0.14	$	1.02	$	0.87
DIVIDENDS DECLARED PER COMMON SHARE	$	0.1650		$	0.1550	$	0.4950	$	0.4650

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2019 AND 2018

UNAUDITED



	Three Months Ended June 30,						Nine Months Ended June 30,
	2019			2018			2019			2018
NET INCOME	$	1,138,555		$	1,087,355		$	8,242,807		$	6,612,746
Other comprehensive income (loss), net of tax:
Interest rate swaps	(457,899		)	18,998			(583,423		)	125,416
Defined benefit plans	(1,913		)	(4,249		)	(5,739		)	(12,747		)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	(459,812		)	14,749			(589,162		)	112,669
COMPREHENSIVE INCOME	$	678,743		$	1,102,104		$	7,653,645		$	6,725,415

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2019 AND 2018

UNAUDITED



	Nine Months Ended June 30, 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
Net Income	—		—		1,138,555			—			1,138,555
Other comprehensive loss	—		—		—			(459,812		)	(459,812		)
Cash dividends declared ($0.165 per share)	—		—		(1,330,739		)	—			(1,330,739		)
Issuance of common stock (20,685 shares)	103,425		310,989		—			—			414,414
Balance - June 30, 2019	$	40,319,785	$	14,179,376	$	31,698,604		$	(1,460,830	)	$	84,736,935

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE THREE-MONTH AND NINE-MONTH PERIODS ENDED JUNE 30, 2019 AND 2018

UNAUDITED



	Nine Months Ended June 30, 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
Net income	—		—		1,087,355			—			1,087,355
Other comprehensive income	—		—		—			14,749			14,749
Cash dividends declared ($0.155 per share)	—		—		(1,237,962		)	—			(1,237,962		)
Issuance of common stock (10,360 shares)	51,800		215,201		—			—			267,001
Balance - June 30, 2018	$	39,928,760	$	12,832,610	$	27,758,594		$	(1,089,595	)	$	79,430,369

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE NINE-MONTH PERIODS ENDED JUNE 30, 2019 AND 2018

UNAUDITED



	Nine Months Ended June 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	8,242,807		$	6,612,746
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	5,821,417			5,297,337
Cost of retirement of utility plant, net	(285,489		)	(177,175		)
Equity in earnings of unconsolidated affiliate	(2,038,417		)	(585,399		)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately	4,846,199			2,711,554
Net cash provided by operating activities	16,586,517			13,859,063
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(16,646,978		)	(16,093,568		)
Investment in unconsolidated affiliate	(16,650,944		)	(5,250,680		)
Proceeds from disposal of equipment	1,819			47,606
Net cash used in investing activities	(33,296,103		)	(21,296,642		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	51,559,000			13,537,000
Repayment of long-term debt	(24,000,000		)	—
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	(92,856		)	(32,678		)
Proceeds from issuance of stock	1,482,430			16,264,655
Cash dividends paid	(3,887,037		)	(3,408,776		)
Net cash provided by financing activities	17,700,520			8,568,441
NET INCREASE IN CASH AND CASH EQUIVALENTS	990,934			1,130,862
BEGINNING CASH AND CASH EQUIVALENTS	247,411			69,640
ENDING CASH AND CASH EQUIVALENTS	$	1,238,345		$	1,200,502
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	2,725,248		$	1,955,847
Income taxes paid	1,951,000			1,180,000

See notes to condensed consolidated financial statements.

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 June 30, 2019, cash flows for the nine months ended June 30, 2019 and 2018 and the results of its operations, comprehensive income and changes in stockholders' equity for the three and nine months ended June 30, 2019 and 2018. The results of operations for the three and nine months ended June 30, 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.

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 follows:



	Three Months Ended June 30, 2018
	As Previously Reported		Effect of Change			As Adjusted
Operations and maintenance	$	2,782,916	$	30,633		$	2,813,549
Total operating expenses	10,023,347		30,633			10,053,980
Operating income	1,866,223		(30,633		)	1,835,590
Other income (expense), net	6,224		30,633			36,857
Income before income taxes	$	1,533,930	$	—		$	1,533,930

	Nine Months Ended June 30, 2018
	As Previously Reported		Effect of Change			As Adjusted
Operations and maintenance	$	9,438,283	$	91,899		$	9,530,182
Total operating expenses	44,715,529		91,899			44,807,428
Operating income	10,848,065		(91,899		)	10,756,166
Other income (expense), net	1,407		91,899			93,306
Income before income taxes	$	9,605,448	$	—		$	9,605,448

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.


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 June 30, 2019								Three months ended June 30, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	5,798,846		$	—	$	5,798,846		$	6,742,368		$	—	$	6,742,368
Commercial	4,116,695			—		4,116,695			3,966,343			—		3,966,343
Industrial and Transportation	1,098,393			—		1,098,393			1,027,430			—		1,027,430
Revenue reductions (TCJA) ⁽¹⁾	—			—		—			(326,486		)	—		(326,486		)
Other	86,714			148,002		234,716			121,026			342,773		463,799
Total contracts with customers	11,100,648			148,002		11,248,650			11,530,681			342,773		11,873,454
Alternative Revenue Programs	434,300			—		434,300			16,116			—		16,116
Total operating revenues	$	11,534,948		$	148,002	$	11,682,950		$	11,546,797		$	342,773	$	11,889,570

	Nine months ended June 30, 2019								Nine months ended June 30, 2018
	Gas utility			Non utility		Total operating revenues			Gas utility			Non utility		Total operating revenues
Natural Gas (Billed and Unbilled):
Residential	$	34,263,845		$	—	$	34,263,845		$	33,468,289		$	—	$	33,468,289
Commercial	19,772,433			—		19,772,433			18,765,110			—		18,765,110
Industrial and Transportation	3,563,505			—		3,563,505			3,289,483			—		3,289,483
Revenue reductions (TCJA) ⁽¹⁾	(523,881		)	—		(523,881		)	(1,147,829		)	—		(1,147,829		)
Other	421,624			544,378		966,002			514,797			888,227		1,403,024
Total contracts with customers	57,497,526			544,378		58,041,904			54,889,850			888,227		55,778,077
Alternative Revenue Programs	132,752			—		132,752			(214,483		)	—		(214,483		)
Total operating revenues	$	57,630,278		$	544,378	$	58,174,656		$	54,675,367		$	888,227	$	55,563,594

(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, 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 monthly based on consumption as measured by metered usage. Revenue is recognized as bills are issued for natural gas that has been delivered or transported. 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, utility-related revenues not directly billed to utility customers and 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 as compared to 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 June 30, 2019	3,637,958		1,149,195		599,736			1,456,665
Increase (decrease)	$	962,347	$	236,108	$	(403,886	)	$	35,622

(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.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company were 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 June 30,						Nine Months Ended June 30,
	2019			2018			2019			2018
Income before income taxes	$	1,482,585		$	1,533,930		$	10,749,678		$	9,605,448
Corporate federal tax rate	21.00		%	24.30		%	21.00		%	24.30		%

Income tax expense computed at the federal statutory rate	$	311,342		$	372,745		$	2,257,432		$	2,334,124
State income taxes, net of federal tax benefit	71,245			70,337			512,315			438,551
Net amortization of excess deferred taxes on regulated operations	(13,624		)	—			(186,041		)	—
Revaluation of unregulated deferred taxes	—			—			—			206,830
Other, net	(24,933		)	3,493			(76,835		)	13,197
Total income tax expense	$	344,030		$	446,575		$	2,506,871		$	2,992,702

Effective tax rate	23.2		%	29.1		%	23.3		%	31.2		%


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.

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, recovery of regulatory assets associated with eligible safety activity costs ("ESAC") and 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. On June 28, 2019, the SCC staff issued their report and recommendations related to the rate application. Management has conducted a detailed review and assessment of each of the SCC staff's recommended adjustments and provided supplemental testimony to certain of the adjustments, including a proposed write-down of a portion of the ESAC regulatory assets. As a result of this assessment, management has revised the Company's estimated provision for refund.

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 June 30, 2019, Roanoke Gas had approximately $11,100,000 remaining in 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 SCC staff report on the general rate case application had no significant changes to the provision for and refund timing of the excess deferred taxes included in regulatory liabilities.

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, included as a component of customer billing rates, until such time as the SCC approves revised billing rates incorporating the lower tax rate. Effective with January 2019 customer billings, the Company began refunding the excess revenues to customers. The SCC staff report on

RGC RESOURCES, INC. AND SUBSIDIARIES

the general rate case application had no significant changes to the provision for and refund timing of the excess deferred taxes or the refund amount for excess revenues included in regulatory liabilities.

The hearing on the rate application is scheduled for August 14, 2019 with the hearing examiner's report and final order anticipated for late first quarter or early second quarter of fiscal 2020. As more information becomes available, the Company will continue to refine its estimated refund until such time as the SCC issues its final order on the rate application.

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's current depreciation rates are based on the last depreciation study filed and implemented in 2014. In June 2019, the Company submitted its current depreciation study and proposed depreciation rates with the SCC. If approved, the proposed rates would result in a small decrease in depreciation expense for fiscal 2019, as the new rates would be effective retroactive to October 1, 2018. Approval of these new depreciation rates is pending at this time with administrative approval anticipated around the Company's fiscal year end.

In May 2019, the Company filed with the SCC its most recent SAVE Plan and Rider. The SAVE Plan provides a mechanism for the Company to recover the related depreciation and expenses and return on rate base of its infrastructure replacement program. The new SAVE filing continues the replacement of first generation plastic main and related services and includes the replacement of a natural gas transfer station. The filing also proposes to extend the Company's SAVE Plan to September 30, 2024. A final order is expected by the end of September.


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. Much of the pipeline has been installed with construction ongoing. The pipeline is currently not expected to be placed in service until mid- 2020 due to ongoing legal issues delaying construction of the pipeline through water crossings and national forest land.

On June 17, 2019, the LLC's managing partner revised the projected cost of the MVP project from $4.6 billion to between $4.8 and $5.0 billion due to the projected 2020 in-service date. As a result, Midstream's estimated total cash contribution will increase to approximately $50 million. 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 is being accounted for under the cost method. Total estimated project cost is between $350 and $500 million, of which Midstream's portion is estimated to be between $1.8 to $2.5 million. The Southgate project is currently in the planning and permitting stage.

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 June 30, 2019, the Company had $7,127,688 remaining to be paid under the most recent notice. The capital contribution payable has been reflected on the Company's Balance Sheet as of June 30, 2019, with a corresponding increase to "investment in unconsolidated affiliates". Related to capital contributions payable, there was a $3,015,078 non-cash decrease in the "investment in unconsolidated affiliates" during the nine months ended June 30, 2019. Funding for Midstream's investments in the LLC for both the MVP and Southgate projects are being provided through two unsecured promissory notes under a non-revolving credit agreement, each with a 5-year term as well as intermediate financing from two additional notes issued in June 2019 as discussed further in Note 7.

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

RGC RESOURCES, INC. AND SUBSIDIARIES



Balance Sheet Location of Other Investments:	June 30, 2019		September 30, 2018
Other Assets:
MVP	$	43,927,960	$	28,387,031
Southgate	253,469		120,115
Investment in unconsolidated affiliates	$	44,181,429	$	28,507,146



Current Liabilities:
MVP	$	7,084,926	$	10,022,652
Southgate	42,762		120,114
Capital contributions payable	$	7,127,688	$	10,142,766



	Three Months Ended				Nine Months Ended
Income Statement Location of Other Investments:	June 30, 2019		June 30, 2018		June 30, 2019		June 30, 2018
Equity in earnings of unconsolidated affiliate	$	777,193	$	245,075	$	2,038,417	$	585,399


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 three interest rate swaps associated with its variable rate debt as discussed in Note 7. Roanoke Gas has a swap agreement that converts its $7,000,000 term note based on LIBOR into fixed-rate debt with a 2.30% effective interest rate. In June 2019, Midstream entered into two swap agreements, one each for the $14,000,000 variable rate term note issued on June 12, 2019 and the $10,000,000 variable rate term note issued on June 13, 2019. The swap agreements convert these two notes into fixed rate instruments with effective interest rates of 3.24% and 3.14%, respectively. The swaps qualify as cash flow hedges with changes in fair value reported in other comprehensive income. No portion of the swaps were deemed ineffective during the periods presented.

The fair value of the current and non-current portions of the interest rate swaps are reflected in the condensed balance sheet under the caption interest rate swap. 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 June 5, 2019, Roanoke Gas entered into an agreement to issue notes in the aggregate principal amount of $10,000,000. These notes are scheduled to be issued on the day of closing currently proposed for December 6, 2019. These notes will have a 10-year term from the date of issue at a fixed interest rate of 3.60%. The proceeds from these notes will be used to finance a portion of Roanoke Gas' capital budget.

On March 28, 2019, Roanoke Gas entered into 12-year unsecured notes in the total principal amount of $10,000,000 with a fixed interest rate of 4.41% per annum. 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.

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%.

On February 19, 2019, Midstream entered into an agreement to amend its existing non-revolving 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.

In June 2019, Midstream entered into two unsecured promissory notes and loan agreements. On June 12, 2019, Midstream entered into a 7-year unsecured note in the aggregate principal amount of $14,000,000 at an interest rate of 30-day LIBOR plus 115 basis points. Midstream also entered into an interest rate swap agreement that converts the note's variable interest rate to a 3.24% fixed rate. On June 13, 2019, Midstream entered into a 5-year unsecured note in the aggregate principal amount of $10,000,000 at an interest rate of 30-day LIBOR plus 120 basis points. Beginning in July 2022, the second note's terms require monthly principal repayments with the remaining unpaid balance due on June 1, 2024. In addition, Midstream entered into a second interest rate swap agreement that converts the second note's variable interest rate to a 3.14% fixed rate.

The proceeds from the notes issued in June 2019 were used to pay down Midstream's notes under the existing non-revolving credit agreement as amended in February. As a result, the corresponding available balances on the prior notes declined by $24,000,000, thereby reducing the previously available $50,000,000 down to $26,000,000. As of June 30, 2019, the total outstanding balances under these notes were $11,302,200.

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:



	June 30, 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	$	147,225	$	30,500,000	$	154,465
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		7,781		7,000,000		10,283
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		39,732		8,000,000		43,343
Unsecured term notes payable, at 4.41% due on March 28, 2031	10,000,000		36,808		—		—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35%, due December 29, 2020	11,302,200		71,405		17,743,200		74,190
Unsecured term note payable, at 30-day LIBOR plus 1.15%, due June 12, 2026	14,000,000		16,853		—		—
Unsecured term note payable, at 30-day LIBOR plus 1.20%, due June 1, 2024	10,000,000		11,590		—		—
Total notes payable	$	90,802,200	$	331,394	$	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	$	90,802,200	$	331,394	$	70,604,217	$	282,281


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 June 30, 2019
Interest rate swaps:
Unrealized losses	$	(592,836	)	$	152,596		$	(440,240	)
Transfer of realized gains to interest expense	(23,780		)	6,121			(17,659		)
Net interest rate swap	(616,616		)	158,717			(457,899		)
Defined benefit plans:
Amortization of actuarial gains	(2,576		)	663			(1,913		)
Other comprehensive loss	$	(619,192	)	$	159,380		$	(459,812	)
Three Months Ended June 30, 2018
Interest rate swap:
Unrealized gains	$	35,969		$	(10,373	)	$	25,596
Transfer of realized gains to interest expense	(9,272		)	2,674			(6,598		)
Net interest rate swap	26,697			(7,699		)	18,998
Defined benefit plans:
Amortization of actuarial gains	(5,971		)	1,722			(4,249		)
Other comprehensive income	$	20,726		$	(5,977	)	$	14,749

RGC RESOURCES, INC. AND SUBSIDIARIES




	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
Nine Months Ended June 30, 2019
Interest rate swap:
Unrealized losses	$	(726,851	)	$	187,091		$	(539,760	)
Transfer of realized gains to interest expense	(58,797		)	15,134			(43,663		)
Net interest rate swap	(785,648		)	202,225			(583,423		)
Defined benefit plans:
Amortization of actuarial gains	(7,728		)	1,989			(5,739		)
Other comprehensive loss	$	(793,376	)	$	204,214		$	(589,162	)
Nine Months Ended June 30, 2018
Interest rate swap:
Unrealized gains	$	187,913		$	(54,194	)	$	133,719
Transfer of realized gains to interest expense	(11,668		)	3,365			(8,303		)
Net interest rate swap	176,245			(50,829		)	125,416
Defined benefit plans:
Amortization of actuarial gains	(17,913		)	5,166			(12,747		)
Other comprehensive income	$	158,332		$	(45,663	)	$	112,669

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	(589,162		)
Balance at June 30, 2019	$	(1,460,830	)


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 generally 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 nine months ended June 30, 2019 and 2018 were calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common

RGC RESOURCES, INC. AND SUBSIDIARIES

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 June 30,				Nine Months Ended June 30,
	2019		2018		2019		2018
Net Income	$	1,138,555	$	1,087,355	$	8,242,807	$	6,612,746
Weighted average common shares	8,051,944		7,982,354		8,029,222		7,533,595
Effect of dilutive securities:
Options to purchase common stock	36,326		48,698		41,830		46,330
Diluted average common shares	8,088,270		8,031,052		8,071,052		7,579,925
Earnings Per Share of Common Stock:
Basic	$	0.14	$	0.14	$	1.03	$	0.88
Diluted	$	0.14	$	0.14	$	1.02	$	0.87


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:



	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Components of net periodic pension cost:
Service cost	$	134,317		$	166,309		$	402,951		$	498,927
Interest cost	291,682			272,045			875,046			816,135
Expected return on plan assets	(387,359		)	(465,710		)	(1,162,077		)	(1,397,130		)
Recognized loss	39,650			87,758			118,950			263,274
Net periodic pension cost	$	78,290		$	60,402		$	234,870		$	181,206



	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
Components of postretirement benefit cost:
Service cost	$	33,221		$	41,805		$	99,663		$	125,415
Interest cost	162,236			160,151			486,708			480,453
Expected return on plan assets	(136,805		)	(155,845		)	(410,415		)	(467,535		)
Recognized loss	30,951			70,967			92,853			212,901
Net postretirement benefit cost	$	89,603		$	117,078		$	268,809		$	351,234

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.

RGC RESOURCES, INC. AND SUBSIDIARIES



	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.

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 June 30, 2019 and September 30, 2018:

RGC RESOURCES, INC. AND SUBSIDIARIES



	Fair Value Measurements - June 30, 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	$	37,067	$	—	$	37,067	$	—
Total	$	37,067	$	—	$	37,067	$	—

Liabilities:
Natural gas purchases	$	277,663	$	—	$	277,663	$	—
Interest rate swap	512,152		—		512,152		—
Total	$	789,815	$	—	$	789,815	$	—

	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 swaps are 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 June 30, 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 June 30, 2019 and September 30, 2018:

RGC RESOURCES, INC. AND SUBSIDIARIES



	Fair Value Measurements - June 30, 2019
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Notes payable	$	90,802,200	$	—	$	—	$	94,425,095
Total	$	90,802,200	$	—	$	—	$	94,425,095

	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 June 30, 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.

RGC RESOURCES, INC. AND SUBSIDIARIES

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 nine-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 nine 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 60,900 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.

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.

The Company currently has a non-gas base rate application pending before the SCC. Roanoke Gas implemented the non-gas rates contained in its rate application for natural gas service rendered to customers on or after January 1, 2019. These non-gas rates are subject to refund pending audit, hearing and a final order issued by the SCC. On June 28, 2019, the SCC staff issued its report and findings from the audit of the rate application. The SCC staff recommended a lower non-gas rate increase requested in the rate application, which is normal and expected. Management provided additional testimony and rebuttal to

RGC RESOURCES, INC. AND SUBSIDIARIES

certain proposed adjustments in response to the SCC staff report. As a result of its review of the proposed adjustments by the SCC and assessment of its position regarding such adjustments, management has established a provision for the estimated refund. In addition, the SCC staff recommended a change in rate design of the non-gas rate increase between customer base charge and volumetric rates, shifting much of the increase in non-gas rates from customer base charge to the volumetric components.

A hearing is scheduled for August 14, 2019 in which the Company will respond to the proposed adjustments to the rate filing. The hearing examiner's report is expected to be issued after the fiscal year end with a final order not expected until late first quarter or early second quarter of fiscal 2020 with customer refunds completed once the order is received.

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 designed to recover 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 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 recorded a regulatory liability related to the excess deferred income taxes on the regulated operations of Roanoke Gas. These excess deferred income taxes are being refunded to customers over a 28-year period. The SCC staff report indicated no changes to the amounts for excess revenue collected and the excess deferred taxes to be refunded to customers. The Company expects to complete the refund of the excess revenues by December and will continue to refund the excess deferred taxes over time. Additional information regarding the TCJA and non-gas base rate application is provided under the Regulatory and Tax Reform section below.

As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of variations in weather and the cost of natural gas, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include 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 nine months ended June 30, 2019, the Company accrued $461,000 and $350,000 in additional revenues under the WNA model for weather that was 46% and 3% warmer than normal, respectively. For the corresponding periods last year, the Company accrued approximately $80,000 in additional revenues for weather that was 9% warmer than normal, and approximately $43,000 reduction in revenues for weather that was 1% colder than normal. The WNA year runs from April 1 to March 31 each year.

The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs,” of its investment in natural gas inventory. This ICC factor applied to the cost of inventory is based on the Company’s weighted-average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances,

RGC RESOURCES, INC. AND SUBSIDIARIES

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 nine month periods ended June 30, 2019 declined by approximately 22% and 14%, respectively, 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 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. Accordingly, SAVE Plan revenues declined by $1,143,000 for the three-month period ended June 30, 2019 compared to the same period last year and by approximately $2,157,000 for the corresponding nine-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 June 30, 2019:

Net income increased by $51,200 for the three months ended June 30, 2019, compared to the same period last year. Quarterly performance improved slightly as the impact of the rate increase combined with the earnings on the Mountain Valley Pipeline investment offset increases in operation and maintenance costs and interest expense.

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



	Three Months Ended June 30,
	2019		2018		Increase / (Decrease)			Percentage
Operating Revenues
Gas Utility	$	11,534,948	$	11,546,797	$	(11,849	)	—	%
Non utility	148,002		342,773		(194,771		)	(57	)%
Total Operating Revenues	$	11,682,950	$	11,889,570	$	(206,620	)	(2	)%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	760,514		988,318		(227,804		)	(23	)%
Transportation and Interruptible	667,711		666,323		1,388			—	%
Total Delivered Volumes	1,428,225		1,654,641		(226,416		)	(14	)%
Heating Degree Days (Unofficial)	185		317		(132		)	(42	)%

Total operating revenues for the three months ended June 30, 2019, compared to the same period last year, declined primarily due to the lower non-utility activity combined with the offsetting effects of the rate increase and lower delivered volumes during the quarter. 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

RGC RESOURCES, INC. AND SUBSIDIARIES

been reduced by an estimate for potential refunds based on the SCC staff report and managements assessments. Net firm volume deliveries declined by 227,804 decatherms. After adjusting for WNA and the transfer of a large commercial customer to firm transportation, total residential and commercial volumes effectively declined by approximately 24,000 decatherms or more than 2%. Non-utility revenue declined as a significant customer had a temporary reduction in service needs during the quarter. Service levels have since returned to more normal levels. In addition, the prior year included a reserve of $326,486 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.



	Three Months Ended June 30,
	2019		2018		Increase / (Decrease)			Percentage
Gas Utility Margin
Utility Revenues	$	11,534,948	$	11,546,797	$	(11,849	)	—	%
Cost of Gas	4,132,871		4,870,683		(737,812		)	(15	)%
Gas Utility Margin	$	7,402,077	$	6,676,114	$	725,963		11	%

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 $1,142,587 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates effective January 1, 2019. As noted above, the SCC staff recommended a change in the proposed rate design of the non-gas rate increase between customer base charge and volumetric rates. In designing the rates submitted in the rate application, the Company included SAVE related revenues in the base charge component as the SAVE rider was previously reflected as a fixed fee on customers bills. As a result, the new rates implemented effective January 1 included a much larger allocation of the rate increase to the customer base charge. The SCC staff recommended in their report to significantly reduce the customer base charge rate and move it to the volumetric component of non-gas rates. Due to staff's position, the Company modified its rate refund assumptions in the current quarter, resulting in a significant reduction in customer base charge revenue and an increase in volumetric revenue. If the same rate refund factors had been applied in March, the accrued refund would have been less during the prior quarter, due to the change in the customer base charge vs volumetric components, and higher during the current quarter. As noted above, the prior year included a reserve of $326,486 related to excess revenues to be refunded to customers due to the reduction in the federal income tax rate.

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



	Three Months Ended June 30,
	2019		2018			Increase / (Decrease)
Customer Base Charge	$	2,616,903	$	3,130,911		$	(514,008	)
Carrying Cost	70,485		89,920			(19,435		)
SAVE Plan	96,483		1,239,070			(1,142,587		)
Volumetric	4,140,562		2,431,276			1,709,286
WNA	461,315		80,317			380,998
Other Gas Revenues	16,329		31,106			(14,777		)
Excess Revenue Refund	—		(326,486		)	326,486
Total	$	7,402,077	$	6,676,114		$	725,963

Operation and maintenance expenses increased by $613,168, or 22%, from the same period last year related to several factors including increased compensation costs, amortization of regulatory assets, corporate insurance costs, reduction in capitalized overheads and higher bad debt expense. Total compensation costs increased by $129,000 due to higher employment levels and wage increases. The Company began amortizing certain regulatory assets that are currently being recovered in the new non-gas base rates. Total amortization expense was $172,000. Corporate insurance costs increased by $96,000 due to increased liability limits and deductible coverage. Total capitalized overheads decreased by $136,000 due to lower capital expenditures

RGC RESOURCES, INC. AND SUBSIDIARIES

and the delayed timing of LNG production. Bad debt expense increased by $34,000 primarily due to the bankruptcy of a commercial account. Most of the remaining difference relates to scheduled maintenance at the LNG plant.

General taxes increased by $36,816, or 8%, associated with higher property and payroll taxes. Property taxes continue to increase corresponding to higher utility property balances related to ongoing infrastructure replacement, system reinforcements and customer growth.

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

Equity in earnings of unconsolidated affiliate increased by $532,118, or more than triple last year, due to the extent of pipeline construction activities in the MVP. The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). 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 decreased by $42,824 primarily due to the adoption of ASU 2017-07, Compensation - Retirement Benefits, as discussed in Note 1, which resulted in the components of net periodic benefit costs other than service cost being presented outside of 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 $342,106, or 59%, due to a 57% 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 higher interest rates on the Company's variable-rate debt. Total Midstream borrowing increased by more than $23 million while the average interest rate increased 43 basis points. Roanoke Gas' total borrowing increased by $10 million with an average interest rate increase of 10 basis points. As a result, the weighted-average effective interest rate on total Company debt increased from 3.97% in the third quarter of fiscal 2018 to 4.03% during the third quarter of fiscal 2019.

Income tax expense decreased by $102,545 due to 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.

Nine Months Ended June 30, 2019:

Net income increased by $1,630,061 for the nine months ended June 30, 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.



	Nine Months Ended June 30,
	2019		2018		Increase / (Decrease)			Percentage
Operating Revenues
Gas Utility	$	57,630,278	$	54,675,367	$	2,954,911		5	%
Non utility	544,378		888,227		(343,849		)	(39	)%
Total Operating Revenues	$	58,174,656	$	55,563,594	$	2,611,062		5	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	6,408,144		6,567,993		(159,849		)	(2	)%
Transportation and Interruptible	2,217,651		2,184,859		32,792			2	%
Total Delivered Volumes	8,625,795		8,752,852		(127,057		)	(1	)%
Heating Degree Days (Unofficial)	3,790		3,948		(158		)	(4	)%

RGC RESOURCES, INC. AND SUBSIDIARIES

Operating revenues for the nine months ended June 30, 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 revised its estimated refund based on on the SCC staff report and managements assessments regarding the final award. Residential and commercial deliveries declined by 159,849 decatherms based on weather that was 4% warmer than the same period last year. After adjusting for WNA and the transfer of a large commercial customer to firm transportation, total residential and commercial volumes actually reflect an increase of 94,000 decatherms, or more than 1%. The average commodity price of natural gas delivered during the first nine months of fiscal 2019 was approximately 5% 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. The prior year included a reserve of $1,147,829 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. Non-utility revenue declined primarily due to reduced customer needs during the third quarter.

See the Regulatory and Tax Reform section below for more information regarding the non-gas rate application.



	Nine Months Ended June 30,
	2019		2018		Increase		Percentage
Gas Utility Margin
Utility Revenues	$	57,630,278	$	54,675,367	$	2,954,911	5	%
Cost of Gas	28,810,668		28,175,366		635,302		2	%
Gas Utility Margin	$	28,819,610	$	26,500,001	$	2,319,609	9	%

Regulated natural gas margins from utility operations increased from the same period last year for the same reason that margins increased for the quarter. Based on the proposed rate design changes submitted by the SCC staff in their report on the non-gas rate application, customer base charges and non-gas volumetric margins increased by $687,159 and $2,864,830, respectively, net of the estimated refund. SAVE revenues declined by $2,156,998 as all related SAVE activities through December 31, 2018 were incorporated into the new non-gas base rates. The reserve for excess revenues related to the reduction in federal income taxes declined by $623,948.

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



	Nine Months Ended June 30,
	2019			2018			Increase / (Decrease)
Customer Base Charge	$	10,066,665		$	9,379,506		$	687,159
Carrying Cost	345,052			400,361			(55,309		)
SAVE Plan	1,327,020			3,484,018			(2,156,998		)
Volumetric	17,177,789			14,312,959			2,864,830
WNA	350,393			(43,448		)	393,841
Other Gas Revenues	76,572			114,434			(37,862		)
Excess Revenue Refund	(523,881		)	(1,147,829		)	623,948
Total	$	28,819,610		$	26,500,001		$	2,319,609

Operation and maintenance expenses increased by $1,132,618, or 12%, from the same period last year for many of the same reasons as reflected in the quarter: higher compensation costs, amortization of regulatory assets, corporate insurance costs, lower capitalized overheads and higher bad debt expense. Total compensation costs increased by $460,000 due to higher employment levels and wage increases. The Company began amortizing certain regulatory assets in January 2019 resulting in an additional $238,000 in expense. Corporate insurance expense increased by $96,000 due to higher premiums related to increased liability limits and higher deductible reserves. Capitalized overheads declined by $67,000 primarily due to timing of LNG production. Bad debt expense increased by $56,000 related to increased customer billings. The remaining increase relates to maintenance work at the LNG plant and other minor items.

RGC RESOURCES, INC. AND SUBSIDIARIES

General taxes increased by $127,862, or 9%, associated with higher property and payroll taxes. The increase in property taxes reflects the ongoing investment in the utility infrastructure of Roanoke Gas while the higher payroll taxes correspond to compensation activity.

Depreciation expense increased by $511,791, or 10%, on higher utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $1,453,018, due to the significant increase in the investment in the MVP project.

Other income (expense), net increased by $148,322 primarily due to the revenue sharing incentive mechanism approved in 2018, partially offset by 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 $805,706, or 44%, due to a 38% 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 3.77% for the first nine months of fiscal 2018 to 3.96% for the same period in fiscal 2019.

Income tax expense declined by $485,831 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 has recorded an estimate for refund related to the implementation of the new non-gas base rates effective January 1, 2019. This estimate reflects the adjustments proposed by the SCC staff in their report issued on June 28, 2019 as well as management's assessment of the likelihood of successfully rebutting certain SCC staff adjustments. As the process continues, management will continue to refine the estimate until a final order is issued.

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 is retained by the Company with the balance passed through to customers through reduced gas costs.

RGC RESOURCES, INC. AND SUBSIDIARIES

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.

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 are proceeding with more than 80% of the project completed. 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 has indicated that the restrictions related to the stream crossings should be resolved this year and access granted to the Jefferson National Forest by next spring. Based on these time lines, the LLC managing partner has revised the projected in-service date to mid-2020.

As a result of the revised time line for completing the MVP as noted above, the LLC revised the estimated project cost to between $4.8 and $5.0 billion from the previous estimate of $4.6 billion with Midstream's estimated cash investment expected to increase to nearly $50 million. Furthermore, the delays in completing the project combined with the increased costs will reduce the corresponding return on investment, absent a regulatory action, which could provide for the recovery of these higher costs.

Midstream issued two intermediate term notes in the amount of $24 million in June 2019 to finance a portion of the investment in MVP. The remainder of the financing for the project will be from the notes under the non-revolving credit agreement with a total capacity of $26 million with $11.3 million outstanding at June 30, 2019.

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 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 by SCC staff, hearing and final order by the SCC.

RGC RESOURCES, INC. AND SUBSIDIARIES

On June 28, 2019, the SCC staff issued their report and recommendations related to the rate application. Management has reviewed the SCC staff's report and plans to submit rebuttal testimony to certain proposed adjustments included in staff's report for the hearing scheduled for August 14, 2019. The major differences with staff's report that management plans to contest include the proposed return on equity, the exclusion of certain infrastructure items from rate base, changes in customer class rate design and the exclusion of a portion of the regulatory assets associated with the ESAC costs. Management has completed a review of each of the SCC staff's recommended adjustments including those that the Company will contest and has reflected their assessments, including revisions to the accrued estimated refund in the consolidated financial statements. Sometime after the hearing, the hearing examiner will issue his report and the SCC Commissioners will make a final determination on the rate application and issue a final order. A final order is not expected until late first quarter or early second quarter of fiscal 2020. As more information becomes available during this process, the Company will continue to refine its estimates and assumptions reflected in the financial statements until such time as the SCC issues its final order and estimates are finalized.

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. As noted above, the SCC staff report recommended excluding approximately $400,000 of these costs from rate recovery. The Company has completed an assessment of the likelihood of a successful challenge to the SCC's position on these assets, which have been reflected in the financial statements. If the SCC ultimately determines to exclude these assets from rate recovery in its final order, then a portion of these assets would be written down to the balance allowed to be recovered.

As noted above, 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 comply with 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 June 30, 2019, Roanoke Gas had approximately $11,100,000 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 a 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 were subject to review and adjustment by the SCC, which was done by its staff in connection with its audit of the rate case application. The SCC staff report agreed with the refund amounts reflected in the Company's financial statements, and assuming no changes during the hearing or by the Commissioners, these amounts will be reflected in the final order.

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. In May 2019, the Company filed its most recent SAVE Plan and Rider, which continues the focus on the ongoing replacement of pre-1973 plastic pipe and the replacement of a natural gas transfer station. If approved, the new SAVE Plan Rider will be effective in October 2019 with SAVE rates designed to collect approximately $1.2 million in annual revenues, an increase from the approximate $500,000 in annual revenues under the current SAVE rates. With the inclusion of all previous SAVE investment through December 31, 2018 into the rate application, the current SAVE Plan Rider reflects only the recovery of qualifying SAVE Plan investments made since the beginning of January 2019. In addition, the SAVE application includes a request to refund approximately $500,000 in SAVE revenue over-collections from 2018, which resulted primarily from the effect of the reduction in income tax rates.

RGC RESOURCES, INC. AND SUBSIDIARIES

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.

On June 14, 2019, Roanoke Gas filed an application with the SCC for authority to issue up to $40 million in short-term debt and up to $100 million of long-term debt or common equity. Roanoke Gas' current financing authorization expires on September 30, 2019. The new authorization request is for 5 years ending on September 30, 2024.

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. On June 11, 2019, Roanoke Gas submitted it's current depreciation study, which incorporates all of the new and replacement infrastructure and equipment placed in service since the last study. The depreciation study is subject to administrative review, and if approved, these new rates will result in a small reduction in depreciation expense. The Company expects to implement the new depreciation rates in its fiscal 2019 fourth quarter.

Capital Resources and Liquidity

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its utility plant capital projects, investment in the MVP, the seasonal funding of its natural gas inventories and accounts receivable and the payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and equity capital.

Cash and cash equivalents increased by $990,934 for the nine-month period ended June 30, 2019, compared to a $1,130,862 increase for the same period last year. The following table summarizes the sources and uses of cash:



	Nine Months Ended June 30,
	2019			2018
Cash Flow Summary
Net cash provided by operating activities	$	16,586,517		$	13,859,063
Net cash used in investing activities	(33,296,103		)	(21,296,642		)
Net cash provided by financing activities	17,700,520			8,568,441
Increase in cash and cash equivalents	$	990,934		$	1,130,862

The seasonal nature of the natural gas business causes operating cash flows to fluctuate significantly during the year as well as from year to year. Factors, including weather, energy prices, natural gas storage levels and customer collections, contribute to working capital levels and the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to increases in natural gas storage levels, rising customer receivable balances and construction activity.

Cash flow provided by operations is primarily driven by net income, depreciation and reductions in natural gas storage inventory during the first nine months of the fiscal year. Cash flow from operating activities increased over the same period last year by $2,727,454 primarily related to higher over-collections of gas costs, lower gas in storage balances and depreciation offset by an increase in accounts receivable and reductions in regulatory liabilities and deferred taxes. Although net income increased by $1.6 million, it did not significantly impact cash flow as much of the increase in net income was attributable to the non-cash equity in earnings from the investment in MVP. Over-collections of gas cost increased by more than $3.5 million over the same period last year. Gas prices spiked in December and futures prices at the time indicated that 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

RGC RESOURCES, INC. AND SUBSIDIARIES

and third fiscal quarters resulting in the increase in over-collections. The combination of lower gas prices and lower storage levels contributed $832,000 to the increase in operating cash. Accounts receivable balances increased by $920,000 over the same period last year primarily as a result of the implementation of new non-gas rates and the inclusion of the WNA receivable. Regulatory liabilities and deferred taxes increased to a lesser degree during the current year, as the amortization of the regulatory liabilities established last year due to tax reform partially offset the current year increase related to the estimated refund associated with the implementation of new non-gas rates. A summary of the cash provided by operations is provided below:



	Nine Months Ended June 30,
Cash Flow From Operating Activities:	2019			2018			Increase / (Decrease)
Net income	$	8,242,807		$	6,612,746		$	1,630,061
Depreciation	5,821,417			5,297,337			524,080
Equity in earnings	(2,038,417		)	(585,399		)	(1,453,018		)
Increase in over/under-collections	3,079,834			(444,961		)	3,524,795
Decrease in gas in storage	3,479,797			2,648,167			831,630
Increase in accounts receivable	(1,706,693		)	(782,920		)	(923,773		)
Increase in regulatory liability and deferred taxes	897,629			1,398,703			(501,074		)
Other	(1,189,857		)	(284,610		)	(905,247		)
Net Cash Provided by Operations	$	16,586,517		$	13,859,063		$	2,727,454

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 MVP, 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 nine months were $16.6 million, or about $500,000 more than the same period last year. Capital expenditures for fiscal 2019 are expected to be near last year's level of $23.3 million.

Investing cash flows also include the Company's continued funding of its participation in the MVP, with a total cash investment of $16.7 million for the nine months ended June 30, 2019 compared to $5.3 million for the corresponding period last year. Total cash investment is expected to be near $50 million by the time MVP is placed into service.

Financing activities generally consist of long-term notes payable and line-of-credit borrowings and repayments, issuance of stock and the payment of dividends. Net cash flows provided by financing activities were $17.7 million for the current period compared to $8.6 million for the same period last year. The increase in financing cash flows is primarily attributable to Midstream's borrowings to finance its investment in MVP and the issuance of notes by Roanoke Gas. Midstream borrowed $17,559,000 under its credit facility and $24,000,000 from two unsecured notes issued in June. Proceeds from the two notes were used to pay down the balance on the credit facility. During the same period last year, Midstream borrowed $5,537,000 under its credit facility as the investment in MVP began to increase. 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.

In June 2019, Midstream entered into two unsecured promissory notes and loan agreements in the total aggregate principal amount of $24,000,000. The first note was for a 7-year term in the amount of $14,000,000 at an interest rate of 30-day LIBOR plus 115 basis points. Midstream entered into a related swap agreement to convert the variable interest rate to a 3.24% fixed rate. The second note was for a 5-year term in the amount of $10,000,000 at an interest rate of 30-day LIBOR plus 120 basis points. Midstream also entered into a swap agreement on this note to convert the variable interest rate to a 3.14% fixed rate.

RGC RESOURCES, INC. AND SUBSIDIARIES

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 non-revolving 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. Midstream used the proceeds from the two notes issued in June to pay down the balance on the notes. As the notes were issued under a non-revolving credit agreement, the borrowing limit under this credit facility was reduced from $50 million to $26 million.

As of June 30, 2019, Resources' long-term capitalization ratio was 48.3% equity and 51.7% debt.

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 June 30, 2019, the Company had no outstanding balance under its variable rate line-of-credit with an average balance outstanding during the nine-month period of $7,416,276. The Company also had $11,302,200 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 nine months ended June 30, 2019 would have resulted in an increase of approximately $271,000 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 June 30, 2019, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 1,421,367 decatherms of gas in storage, including LNG, at an average price of $2.92 per decatherm, compared to 1,641,236 decatherms at an average price of $3.08 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.

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 June 30, 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 June 30, 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 June 30, 2019, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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		Promissory Note in the original principal amount of $14,000,000 by and between RGC Midstream, LLC and Atlantic Union Bank dated June 12, 2019 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.2		Loan Agreement between RGC Midstream, LLC and Atlantic Union Bank dated June 12, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.3		Unconditional Guaranty by and between RGC Resources, Inc. and Atlantic Union Bank (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.4		Swap Agreement by and between RGC Midstream, LLC and Atlantic Union Bank, dated June 12, 2019 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.5		Promissory Note in the original principal amount of $10,000,000 by and between RGC Midstream, LLC and Branch Banking and Trust dated June 13, 2019 (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.6		Term Loan Agreement between RGC Midstream, LLC and Branch Banking and Trust dated June 13, 2019 (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.7		Unconditional Guaranty by and between RGC Resources, Inc. and Branch Banking and Trust (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on June 17, 2019).
10.8		Swap Agreement by and between RGC Midstream, LLC and Branch Banking and Trust, dated June 13, 2019 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on June 17, 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 June 30, 2019, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at June 30, 2019 and September 30, 2018, (ii) Condensed Consolidated Statements of Income for the three months and nine months ended June 30, 2019 and 2018; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended June 30, 2019 and 2018; (iv) Condensed Consolidated Statements of Changes in Stockholders' Equity for the three months and nine months ended June 30, 2019 and 2018; (v) Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 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.

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: August 6, 2019	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Secretary, Treasurer and CFO