RGC RESOURCES INC - Quarter Report: 2018 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, 2018

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	¨

		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, 2018
Common Stock, $5 Par Value		7,986,856

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	Unaudited
	June 30, 2018			September 30, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,200,502		$	69,640
Accounts receivable (less allowance for uncollectibles of $347,175 and $99,456, respectively)	4,027,904			3,492,703
Materials and supplies	1,059,181			1,021,191
Gas in storage	5,053,727			7,701,894
Prepaid income taxes	234,997			1,796,825
Interest rate swap	87,926			26,777
Other	1,478,827			1,576,574
Total current assets	13,143,064			15,685,604
UTILITY PROPERTY:
In service	211,493,563			204,223,714
Accumulated depreciation and amortization	(62,442,675		)	(59,765,987		)
In service, net	149,050,888			144,457,727
Construction work in progress	12,054,375			3,470,244
Utility plant, net	161,105,263			147,927,971
OTHER ASSETS:
Regulatory assets	11,791,176			11,796,260
Investment in unconsolidated affiliate	22,026,401			7,445,106
Interest rate swap	205,162			90,066
Other	484,661			190,064
Total other assets	34,507,400			19,521,496
TOTAL ASSETS	$	208,755,727		$	183,135,071

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	Unaudited
	June 30, 2018			September 30, 2017
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Dividends payable	$	1,241,678		$	1,050,281
Accounts payable	6,789,299			5,122,899
Capital contributions payable	9,800,720			1,055,504
Customer credit balances	612,140			1,220,578
Customer deposits	1,481,512			1,471,960
Accrued expenses	2,488,378			3,006,936
Over-recovery of gas costs	993,113			1,438,074
Rate refund	1,147,829			—
Total current liabilities	24,554,669			14,366,232
LONG-TERM DEBT:
Notes payable	57,349,200			43,812,200
Line-of-credit	—			17,791,760
Less unamortized debt issuance costs	(294,976		)	(291,949		)
Long-term debt net of unamortized debt issuance costs	57,054,224			61,312,011
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	6,275,752			6,069,993
Regulatory cost of retirement obligations	10,896,740			10,055,189
Benefit plan liabilities	7,170,588			8,214,326
Deferred income taxes	11,631,111			23,076,848
Regulatory liability - deferred income taxes	11,742,274			—
Total deferred credits and other liabilities	47,716,465			47,416,356
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,985,752 and 7,240,846, respectively	39,928,760			36,204,230
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	12,832,610			292,485
Retained earnings	27,758,594			24,746,021
Accumulated other comprehensive loss	(1,089,595		)	(1,202,264		)
Total stockholders’ equity	79,430,369			60,040,472
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	208,755,727		$	183,135,071

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, 2018 AND 2017

UNAUDITED



	Three Months Ended June 30,					Nine Months Ended June 30,
	2018			2017		2018			2017
OPERATING REVENUES:
Gas utility	$	11,546,797		$	11,171,499	$	54,675,367		$	51,346,456
Non-utility	342,773			264,325		888,227			777,966
Total operating revenues	11,889,570			11,435,824		55,563,594			52,124,422
OPERATING EXPENSES:
Cost of gas - utility	4,870,683			4,679,047		28,175,366			24,862,147
Cost of sales - non utility	176,728			122,375		465,925			407,238
Operations and maintenance	2,782,916			3,294,939		9,438,283			9,880,293
General taxes	458,142			450,528		1,431,321			1,372,870
Depreciation and amortization	1,734,878			1,560,728		5,204,634			4,702,185
Total operating expenses	10,023,347			10,107,617		44,715,529			41,224,733
OPERATING INCOME	1,866,223			1,328,207		10,848,065			10,899,689
Equity in earnings of unconsolidated affiliate	245,075			111,626		585,399			289,791
Other (income) expense, net	(6,224		)	8,738		(1,407		)	23,020
Interest expense	583,592			472,300		1,829,423			1,400,301
INCOME BEFORE INCOME TAXES	1,533,930			958,795		9,605,448			9,766,159
INCOME TAX EXPENSE	446,575			343,233		2,992,702			3,693,180
NET INCOME	$	1,087,355		$	615,562	$	6,612,746		$	6,072,979
BASIC EARNINGS PER COMMON SHARE	$	0.14		$	0.09	$	0.88		$	0.84
DILUTED EARNINGS PER COMMON SHARE	$	0.14		$	0.08	$	0.87		$	0.84
DIVIDENDS DECLARED PER COMMON SHARE	$	0.1550		$	0.1450	$	0.4650		$	0.4350

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, 2018 AND 2017

UNAUDITED



	Three Months Ended June 30,						Nine Months Ended June 30,
	2018			2017			2018			2017
NET INCOME	$	1,087,355		$	615,562		$	6,612,746		$	6,072,979
Other comprehensive income (loss), net of tax:
Interest rate swap	18,998			(25,053		)	125,416			73,583
Defined benefit plans	(4,249		)	39,742			(12,747		)	119,226
OTHER COMPREHENSIVE INCOME, NET OF TAX	14,749			14,689			112,669			192,809
COMPREHENSIVE INCOME	$	1,102,104		$	630,251		$	6,725,415		$	6,265,788

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, 2018 AND 2017

UNAUDITED



	Nine Months Ended June 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6,612,746		$	6,072,979
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	5,297,337			4,793,270
Cost of removal of utility plant, net	(177,175		)	(236,292		)
Stock option grants	—			73,780
Equity in earnings of unconsolidated affiliate	(585,399		)	(289,791		)
Changes in assets and liabilities which provided cash, exclusive of changes and noncash transactions shown separately	2,711,554			5,337,120
Net cash provided by operating activities	13,859,063			15,751,066
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(16,093,568		)	(16,451,865		)
Investment in unconsolidated affiliate	(5,250,680		)	(1,803,100		)
Proceeds from disposal of equipment	47,606			13,971
Net cash used in investing activities	(21,296,642		)	(18,240,994		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	13,537,000			8,924,000
Borrowings under line-of-credit agreement	19,533,761			31,170,307
Repayments under line-of-credit agreement	(37,325,521		)	(35,210,666		)
Debt issuance costs	(32,678		)	(16,675		)
Proceeds from issuance of stock (744,906 and 49,101 shares, respectively)	16,264,655			810,689
Cash dividends paid	(3,408,776		)	(3,067,163		)
Net cash provided by financing activities	8,568,441			2,610,492
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,130,862			120,564
BEGINNING CASH AND CASH EQUIVALENTS	69,640			643,252
ENDING CASH AND CASH EQUIVALENTS	$	1,200,502		$	763,816
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	1,955,847		$	1,598,629
Income taxes paid	1,180,000			51,000

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, 2018 and the results of its operations, cash flows and comprehensive income for the three and nine months ended June 30, 2018 and 2017. The results of operations for the three and nine months ended June 30, 2018 are not indicative of the results to be expected for the fiscal year ending September 30, 2018 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, 2017. The September 30, 2017 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, 2017. Newly adopted and newly issued accounting standards are discussed below.

Certain reclassifications have been made to the prior year income statements to be consistent with the current year presentation by moving cost of gas - utility and cost of sales - non utility under the operating expenses caption. This reclassification makes the Company's income statement presentation consistent with industry peers.

Recently Issued or Adopted Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14 that deferred the effective date of this guidance by one year making the standard effective for the Company's annual reporting period ending September 30, 2019 and interim periods within that annual period. Subsequent ASUs have been issued, which provide additional guidance to assist in the implementation of the new revenue standard. As of June 30, 2018, the Company is completing the review and evaluation of its revenue streams and does not anticipate the adoption of the new standard to have material impact on its financial position, results of operations or cash flows; however, significant new disclosures will be required as a result of the guidance. The Company plans to adopt the new guidance in the first quarter of fiscal 2019 using the modified retrospective approach.

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 new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Management has not completed its evaluation of the new guidance; however, the Company does not currently expect the new guidance to have a material effect on its 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. Management has not completed its evaluation of the new guidance under ASUs 2016-02 and 2018-01; however, 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 January 2017, the FASB issued ASU 2017-03, Accounting Changes and Error Corrections and Investments - Equity Method and Joint Ventures. This update adds the text of the SEC Staff Announcement, Disclosure of the Impact That Recently Issued Accounting Standards Will Have on the Financial Statements of a Registrant When Such Standards Are Adopted in a Future Period (in accordance with Staff Accounting Bulletin Topic 11.M) as paragraph 250-10-S99-6. Related specifically to ASU 2014-09, ASU 2016-02 and ASU 2016-13, an SEC registrant should evaluate ASUs that have not yet been adopted to determine and include appropriate financial disclosures and MD&A discussions, including consideration of additional qualitative disclosures, to assist financial statement readers in assessing the significance of impact on adoption. The new guidance is effective immediately. The nature of this guidance relates to the effectiveness and quality of disclosures related to ASUs not yet adopted; however, there is no effect on the Company's 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. In addition, the ASU allows only the service cost component of periodic benefit cost to be eligible for capitalization when applicable. This change to capitalization eligibility differs from the treatment currently applied by the Company. The new guidance is effective for the Company for the annual reporting period ending September 30, 2019 and interim periods within that annual period. Early adoption is permitted. 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 intends to adopt this ASU effective October 1, 2018 with the change in expense classification on a retrospective basis and the change in capitalization of costs beginning prospectively. If the regulatory body ultimately determines that changes to the capitalization of these retirement benefits is 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. Management does not expect the new guidance to 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 February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The ASU provides the option to reclassify stranded tax effects within AOCI to retained earnings in each period in which the effects of the change in the U.S. federal corporate income tax rate, per the Tax Cuts and Jobs Act, is recorded. The new guidance is effective for the Company for the annual reporting period ending September 30, 2020 and interim periods within that annual period. Early adoption is permitted. Management has not completed its evaluation of the new guidance; however, it believes the new guidance will improve the presentation of AOCI by removing the stranded tax effects related to tax reform and transferring the amount to retained earnings. 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.	Stock Issue

In March 2018, the Company issued 700,000 shares of common stock resulting in proceeds of $15,114,823 net of underwriting and other expenses. The Company issued the common stock primarily to provide funding for Roanoke Gas' infrastructure improvement and replacement programs. The stock issue also strengthened the Company's balance sheet by increasing the equity component of its total capitalization ratio.


3.	Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act, ("Tax Act") became law. The most significant impact of the new law is 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, the Company will have a transition or blended rate of 24.3% determined based on the number of days of the Company's fiscal year at 34% and the number of days in the year at 21%.

Under the provisions of ASC 740 - Income Taxes, the deferred tax assets and liabilities of the Company must be revalued to reflect the reduction in the federal tax rate. Furthermore, revaluing the deferred tax balances to the ultimate 21% federal tax rate required the Company to project the deferred tax activity for the balance of the year and to estimate the impact to current taxes based on the valuation adjustments to this activity.

In accordance with the guidance provided by the SEC Staff Accounting Bulletin ("SAB") 118, the Company has made reasonable estimates of the effect of the tax rate change on its deferred tax assets and liabilities. As of December 31, 2017, the Company reduced the net deferred tax liability by $11,533,986 to revalue the liability from a 34% federal tax rate to a 21% federal tax rate. $11,742,274 related to Roanoke Gas and was reclassified to a regulatory liability as discussed in Note 4, while $208,288 was charged to income tax expense during the first quarter related to the unregulated operations of the Company. These estimates are subject to further clarification of provisions of the Tax Act and regulatory approvals from Roanoke Gas' regulatory body.


4.	Rates and Regulatory Matters

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

As referenced in Note 3, the Tax Act provides for a reduction in the federal corporate tax rate to 21%. The Company has 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 through 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

RGC RESOURCES, INC. AND SUBSIDIARIES

refundable to customers. Roanoke Gas established a regulatory liability in the amount of $11,742,274 related to these excess deferred income taxes.

With the implementation of the Tax Act, the Company has a blended federal tax rate of 24.3% for the current fiscal year. On January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for excess revenues collected from customers attributable to the higher federal income tax rate, currently included as a component of customer billing rates, until such time as the SCC approves lower billing rates incorporating the lower tax rate. For the nine-month period through June 30, 2018, the Company has recorded a reduction to revenue and established a regulatory liability in the amount of $1,147,829 reflecting the estimated excess revenue collected from customers since October 1, 2017. The reduction in the estimated excess revenues is expected to correlate with a similar reduction in corporate income tax expense for the regulated operations of Roanoke Gas for the fiscal year. However, the impact to revenues and tax expense on a quarterly basis is subject to variability and will result in variations in net income with the corresponding quarters in the prior fiscal year. This refund of excess revenue as well as the regulatory liability related to the excess deferred taxes on Roanoke Gas are estimates based on the best information currently available. These estimates will be adjusted as necessary in future financial statements once the SCC completes their review and issues a final order. The amount and timing of the refunds will ultimately be determined by the SCC.

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 a monthly utilization fee. In February 2018, Roanoke Gas filed an application with the SCC for a gas supply incentive mechanism, requesting that the Company be allowed to share the utilization fee credit with its customers. In June 2018, the SCC issued an order approving, retroactive to April 2018, the incentive mechanism, whereby for annual periods beginning April and running through March, customers would receive the initial $700,000 of the utilization fee collected through reduced gas costs and thereafter every additional dollar received during the annual period would be split with 25% to the Company under the incentive mechanism and 75% to benefit its customers. With the retroactive application back to April 2018, the Company did not recognize any amount under the incentive mechanism during the current quarter. Beginning in July 2018, the Company will begin recognizing its 25% income portion as the $700,000 threshold will have been met.


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 a natural gas pipeline originating in northern West Virginia and extending through south central Virginia. The proposed pipeline will have the capacity to transport approximately 2 million decatherms of natural gas per day. The pipeline has received Federal Energy Regulatory Commission ("FERC") approval and is under construction.

The total project cost is estimated by the LLC managing partner to be between $3.5 billion and $3.7 billion. The Company's 1% equity interest in the LLC will require a total estimated cash investment of between $35 million and $37 million, by periodic capital contributions throughout the design and construction phases of the project. On a quarterly basis, the LLC issues a capital call notice, which specifies the capital contributions to be paid over the subsequent 3 months. As of June 30, 2018, the Company had $9,800,720 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, 2018, with a corresponding increase to Investment in unconsolidated affiliate. Related to capital contributions payable, there was a non-cash $8,745,216 increase in the Investment in unconsolidated affiliate in the nine months ended June 30, 2018. Funding for Midstream's investment in the LLC is being provided through two unsecured promissory notes, each with a 5-year term.

The Company is participating in the earnings of the LLC in proportion to its level of investment. The Company is utilizing the equity method to account for the transactions and activity of the investment.

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



Balance Sheet Location of Other Investments:	June 30, 2018		September 30, 2017
Other Assets:
Investment in unconsolidated affiliate	$	22,026,401	$	7,445,106

RGC RESOURCES, INC. AND SUBSIDIARIES



Current Liabilities:
Capital contributions payable	$	9,800,720	$	1,055,504



	Three Months Ended				Nine Months Ended
Income Statement Location of Other Investments:	June 30, 2018		June 30, 2017		June 30, 2018		June 30, 2017
Equity in earnings of unconsolidated affiliate	$	245,075	$	111,626	$	585,399	$	289,791


6.	Derivatives and Hedging

The Company’s risk management policy allows management to enter into derivatives for the purpose of managing the commodity and financial market risks of its business operations. The Company’s risk management policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that the Company seeks to hedge include the price of natural gas and the cost of borrowed funds.

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

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



	June 30, 2018	September 30, 2017
Derivative designated as hedging instrument:
Current assets:
Interest rate swap	$87,926	$26,777

Other assets:
Interest rate swap	$205,162	$90,066

Total derivatives designed as hedging instruments	$293,088	$116,843

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 October 2, 2017, Roanoke Gas entered into ten-year unsecured notes in the total principal amount of $8,000,000 with a fixed interest rate of 3.58% per annum. The proceeds from the notes were used to convert a portion of the Company's line-of-credit balance into longer-term financing.

On March 26, 2018, Roanoke Gas entered into a new unsecured line-of-credit agreement. This new agreement replaced the prior line-of-credit agreement scheduled to expire March 31, 2019. The new agreement is for a two-year term expiring March 31, 2020 with a maximum borrowing limit of $25,000,000. Amounts drawn against the new 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 new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis points. The prior agreement was replaced to revise the 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 new agreement range from $2,000,000 to $25,000,000.

Roanoke Gas has a 5-year unsecured note in the principal amount of $7,000,000. This note is variable rate with interest based on 30-day LIBOR plus 90 basis points with the interest rate hedged by a swap agreement which converts the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%.

On April 11, 2018, Midstream entered into the First Amendment to Credit Agreement ("Amendment") and amendments to the two related Promissory Notes ("Notes") originally issued in December 2015 to finance the capital investment in the LLC. Under the amended agreements, Midstream's total borrowing limits increased from $25 million to $38 million and the interest rate declined to 30-day LIBOR plus 135 basis points. The Amendment now allows for the entire investment in the LLC to be funded through the amended Notes. The increased limits under the Notes provide Midstream with additional funding resources in the event the cost of its investment in the LLC exceeds current projections.

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, 2018				September 30, 2017
	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	$	156,879	$	30,500,000	$	164,119
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		11,116		7,000,000		13,618
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000		44,548		—		48,160
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.35%, due December 29, 2020	11,849,200		82,433		6,312,200		66,052
Total notes payable	$	57,349,200	$	294,976	$	43,812,200	$	291,949
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2020	$	—	$	—	$	17,791,760	$	—
Total long-term debt	$	57,349,200	$	294,976	$	61,603,960	$	291,949


8.	Other Comprehensive Income

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

RGC RESOURCES, INC. AND SUBSIDIARIES



	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
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
Three Months Ended June 30, 2017
Interest rate swap:
Unrealized losses	$	(40,382	)	$	15,329		$	(25,053	)
Defined benefit plans:
Amortization of actuarial losses	64,058			(24,316		)	39,742
Other comprehensive income	$	23,676		$	(8,987	)	$	14,689




	Before-Tax Amount			Tax (Expense) or Benefit			Net-of-Tax Amount
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
Nine Months Ended June 30, 2017
Interest rate swap:
Unrealized gains	$	118,606		$	(45,023	)	$	73,583
Defined benefit plans:
Amortization of actuarial losses	192,174			(72,948		)	119,226
Other comprehensive income	$	310,780		$	(117,971	)	$	192,809

The amortization of actuarial losses is included as a component of net periodic pension and postretirement benefit cost in operations and maintenance expense.

Reconciliation of Other Accumulated Comprehensive Income (Loss)



	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2017	$	(1,202,264	)
Other comprehensive income	112,669
Balance at June 30, 2018	$	(1,089,595	)


9.	Commitments and Contingencies

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

Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply through an asset manager. 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 Mountain Valley Pipeline will provide Roanoke Gas with access to an additional delivery source to its distribution system.


10.	Earnings Per Share

Basic earnings per common share for the three months and nine months ended June 30, 2018 and 2017 were calculated by dividing net income by the weighted average common shares outstanding during the period. Diluted earnings per common share were calculated by dividing net income by the weighted average common shares outstanding during the period plus potential dilutive common shares. A reconciliation of basic and diluted earnings per share is presented below:



	Three Months Ended June 30,				Nine Months Ended June 30,
	2018		2017		2018		2017
Net Income	$	1,087,355	$	615,562	$	6,612,746	$	6,072,979
Weighted average common shares	7,982,354		7,227,171		7,533,595		7,212,289
Effect of dilutive securities:
Options to purchase common stock	48,698		46,669		46,330		32,275
Diluted average common shares	8,031,052		7,273,840		7,579,925		7,244,564
Earnings Per Share of Common Stock:
Basic	$	0.14	$	0.09	$	0.88	$	0.84
Diluted	$	0.14	$	0.08	$	0.87	$	0.84


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 and provides retirement income based on years of service and employee compensation. The postretirement plan provides certain health care and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and postretirement plan expense recorded by the Company is detailed as follows:



	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Components of net periodic pension cost:
Service cost	$	166,309		$	176,669		$	498,927		$	530,007
Interest cost	272,045			248,900			816,135			746,700
Expected return on plan assets	(465,710		)	(404,103		)	(1,397,130		)	(1,212,309		)
Recognized loss	87,758			165,545			263,274			496,635
Net periodic pension cost	$	60,402		$	187,011		$	181,206		$	561,033

RGC RESOURCES, INC. AND SUBSIDIARIES



	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
Components of postretirement benefit cost:
Service cost	$	41,805		$	45,817		$	125,415		$	137,451
Interest cost	160,151			156,706			480,453			470,118
Expected return on plan assets	(155,845		)	(142,878		)	(467,535		)	(428,634		)
Recognized loss	70,967			107,440			212,901			322,320
Net postretirement benefit cost	$	117,078		$	167,085		$	351,234		$	501,255

The table below reflects the Company's actual contributions made fiscal year-to-date. The Company revised its funding plan and currently does not expect to make any further contributions to either the pension plan or the postretirement medical plan for the balance of the current fiscal year.



	Fiscal Year-to-Date Contributions		Remaining Fiscal Year Contributions
Defined benefit pension plan	$	800,000	$	—
Postretirement medical plan	300,000		—
Total	$	1,100,000	$	—


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, 2018 and September 30, 2017:

RGC RESOURCES, INC. AND SUBSIDIARIES



			Fair Value Measurements - June 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	$	293,088	$	—	$	293,088	$	—
Total	$	293,088	$	—	$	293,088	$	—

Liabilities:
Natural gas purchases	$	1,556,372	$	—	$	1,556,372	$	—
Total	$	1,556,372	$	—	$	1,556,372	$	—

			Fair Value Measurements - September 30, 2017
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	116,843	$	—	$	116,843	$	—
Total	$	116,843	$	—	$	116,843	$	—

Liabilities:
Natural gas purchases	$	805,159	$	—	$	805,159	$	—
Total	$	805,159	$	—	$	805,159	$	—

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

Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on weighted average first of the month index prices corresponding to the month of the scheduled payment. At June 30, 2018 and September 30, 2017, 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, 2018 and September 30, 2017:

RGC RESOURCES, INC. AND SUBSIDIARIES



			Fair Value Measurements - June 30, 2018
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt	$	57,349,200	$	—	$	—	$	56,910,578
Total	$	57,349,200	$	—	$	—	$	56,910,578

			Fair Value Measurements - September 30, 2017
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt	$	43,812,200	$	—	$	—	$	45,689,238
Total	$	43,812,200	$	—	$	—	$	45,689,238

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

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, 2018 and September 30, 2017, 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

On August 3, 2018, FERC issued an order directing the immediate halt to the construction of the Mountain Valley Pipeline pending re-evaluation of environmental issues by the U.S. Forest Service and the Bureau of Land Management. Due to the legal challenges, the LLC is evaluating its construction plan for the Mountain Valley Pipeline on a daily basis and moved its target in-service date for the pipeline from the fourth quarter of calendar 2018 to the first quarter of calendar 2019.

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, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” in the Company’s 2017 Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.

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

The three-month 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, 2018. The total revenues and margins realized during the first nine months reflect higher billings due to the weather sensitive nature of the gas business.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,500 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

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

The Company’s utility operations are regulated by the SCC, which oversees the terms, conditions, and rates to be charged to customers for natural gas service, safety standards, extension of service, accounting and depreciation. The Company is also subject to federal regulation from the Department of Transportation in regard to the construction, operation, maintenance, safety and integrity of its transmission and distribution pipelines. The Federal Energy Regulatory Commission ("FERC") regulates the prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.

On December 22, 2017, the President signed into law the Tax Cuts and Job Act ("Tax Act") which provided sweeping changes to the federal income tax code. The most significant change for the Company is the reduction in the corporate maximum federal income tax rate from 35% to 21%. Under the provisions of the law, the Company began applying the lower corporate income tax rate to earnings beginning this current fiscal year in addition to revaluing its deferred tax assets and liabilities derived from the Company's 34% corporate tax rate down to a 21% tax rate. For the unregulated operations of the Company, the effect of the change in tax rate and revaluation of the deferred taxes are reflected in income tax expense. However, for the regulated operations of Roanoke Gas, the net estimated deferred tax liability adjustment of $11,742,274 was transferred to a regulatory liability for refund to customers, and a rate refund liability in the amount of $1,147,829 has been recorded for the estimated excess billings of customers during the first 9 months of the year as the Company's billing rates were designed to recover the operating expenses and provide a rate of return based on a federal tax rate of 34%. Additional information regarding the Tax Act and its impact on the Company is provided under the Tax Reform and Regulatory section below.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

As the Company’s business is seasonal in nature, volatility in winter weather and the commodity price of natural gas can impact the effectiveness of the Company’s rates in recovering its costs and providing a reasonable return for its shareholders. In order to mitigate the effect of variations in weather and the cost of natural gas, the Company has certain approved rate mechanisms in place that help provide stability in earnings, adjust for volatility in the price of natural gas and provide a return on increased infrastructure investment. These mechanisms include a purchased gas adjustment factor ("PGA"), weather normalization adjustment factor ("WNA"), inventory carrying cost revenue ("ICC") and a Steps to Advance Virginia Energy ("SAVE") adjustment rider.

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, or more frequently if necessary, the Company files a PGA rate adjustment request with the SCC to adjust the gas cost component of its rates up or down depending on projected price and activity. Once administrative approval is received, the Company adjusts the gas cost component of its rates to reflect the approved amount. As actual costs will differ from the projections used in establishing the PGA rate, the Company will either over-recover or under-recover its actual gas costs during the period. The difference between actual costs incurred and costs recovered through the application of the PGA is recorded as a regulatory asset or liability. At the end of the annual deferral period, the balance is amortized over an ensuing 12-month period as 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 price protection when the weather is colder than normal. The WNA is based on a weather measurement band around the most recent 30-year temperature average. Under the WNA, the Company recovers from its customers the lost margin (excluding gas costs) for the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months ended June 30, 2018 and 2017, the Company accrued approximately $80,000 and $255,000 in additional revenue for weather that was warmer than normal during each of the periods, respectively. For the nine months ended June 30, 2018, the Company accrued approximately $43,000 reduction in revenues for weather that was 1% colder than normal. For the corresponding nine-month period ended June 30, 2017, the Company accrued $1,860,000 in additional revenues for weather that was 19% warmer than normal.

The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs,” of its investment in natural gas inventory. This ICC factor applied to the cost of inventory is based on the Company’s weighted-average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted-average cost of capital. The average unit price of gas in storage during the first nine months of the current fiscal year was $0.20 per decatherm, or 6.5%, higher than the same period last year, as natural gas commodity prices were higher during the 2017 storage fill season as compared to 2016. During the first three months of fiscal 2018, the average price of gas delivered into storage is below the price of 2017 deliveries. Although ICC revenues are below last year's levels for the quarter and year-to-date, the equity investment in Roanoke Gas will increase the weighted-average cost of capital and the ICC factor going forward leading to potentially higher ICC revenues.

The Company’s non-gas rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved to include the additional investment in new non-gas rates. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure

RGC RESOURCES, INC. AND SUBSIDIARIES

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 did not file for an increase in non-gas rates during the prior four years and the level of capital investment continues to grow, SAVE Plan revenues have continued to increase corresponding to the growth in qualified SAVE related infrastructure projects. The Company recognized approximately $1,239,000 and $3,484,000 in SAVE Plan revenues for the three-month and nine-month periods ended June 30, 2018, compared to approximately $965,000 and $2,768,000 for the same periods last year. These SAVE Plan revenues will be included as part of the new non-gas base rates in the Company's upcoming rate case filing as discussed under the Regulatory and Tax Reform section below.

Results of Operations

Three Months Ended June 30, 2018:

Net income increased by $471,793 for the three months ended June 30, 2018, compared to the same period last year. Improved quarterly performance is attributable to increased revenues from the SAVE Plan, customer growth and lower operating and maintenance expenses, net of the effect of the accrued refund for excess revenues collected from customers related to the reduction in income tax expense resulting from the lower federal income tax rate. A more detailed explanation of the quarterly effect on net income related to the reduction in revenues mandated by the SCC and the reduction in tax expense associated with the Tax Act is provided under the Regulatory and Tax Reform section below.

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



	Three Months Ended June 30,
	2018		2017		Increase		Percentage
Operating Revenues
Gas Utility	$	11,546,797	$	11,171,499	$	375,298	3	%
Non-utility	342,773		264,325		78,448		30	%
Total Operating Revenues	$	11,889,570	$	11,435,824	$	453,746	4	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	988,318		769,795		218,523		28	%
Transportation and Interruptible	666,323		631,297		35,026		6	%
Total Delivered Volumes	1,654,641		1,401,092		253,549		18	%
Heating Degree Days (Unofficial)	317		245		72		29	%

Total operating revenues for the three months ended June 30, 2018, compared to the same period last year, increased due to a combination of increased natural gas deliveries related to a cooler spring, higher SAVE revenues and customer growth more than offsetting the excess revenue adjustment and lower average natural gas commodity prices. Total delivered volumes increased by 18% as evidenced by the 29% increase in heating degree days. The 317 heating degree days were actually 9% warmer than normal but 29% colder than the same period last year. SAVE Plan revenues grew by 21% due to the Company's ongoing investment in its SAVE related infrastructure replacement program. The average commodity price of natural gas delivered during the current quarter was approximately 13% per decatherm lower than the same period last year. The Company recorded a reserve in the amount 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.



	Three Months Ended June 30,
	2018		2017		Increase		Percentage
Gas Utility Margin
Utility Revenues	$	11,546,797	$	11,171,499	$	375,298	3	%
Cost of Gas	4,870,683		4,679,047		191,636		4	%
Gas Utility Margin	$	6,676,114	$	6,492,452	$	183,662	3	%

RGC RESOURCES, INC. AND SUBSIDIARIES

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 increased SAVE revenues and customer growth offsetting the adjustment to reduce revenues for the impact of the estimated excess billings to customers as a result of the reduction in the corporate federal income tax rate. SAVE revenues increased by $274,373 as discussed in more detail above. Volumetric margins net of the WNA adjustment and customer base charge increased due to customer growth, increased usage by commercial customers and heating degree day sensitivity during the spring months. Gas utility margin was reduced for the estimated excess revenues deferred to a regulatory liability related to the reduction in the federal corporate income tax rate. More information is provided under the Regulatory and Tax Reform section below.

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



	Three Months Ended June 30,
	2018			2017		Increase / (Decrease)
Customer Base Charge	$	3,130,911		$	3,112,654	$	18,257
Carrying Cost	89,920			107,051		(17,131		)
SAVE Plan	1,239,070			964,697		274,373
Volumetric	2,431,276			2,025,593		405,683
WNA	80,317			255,163		(174,846		)
Other Gas Revenues	31,106			27,294		3,812
Excess Revenue Refund	(326,486		)	—		(326,486		)
Total	$	6,676,114		$	6,492,452	$	183,662

Operation and maintenance expenses decreased by $512,023, or 16%, from the same period last year primarily related to several factors including higher capitalized overheads, lower benefit costs and the absence of severance costs related to the outsourcing of customer support services function last year. Total capitalized overheads increased by $254,000, due to a 67% rise in capital expenditures subject to overhead capitalization, compared to the same period last year. The increase in capital expenditures for the quarter correspond to improved weather conditions, favorable progress on current year projects and timing of prior year expenditures. Total capital expenditures for fiscal 2018 are expected to exceed fiscal 2017. Employee benefit costs declined by $187,000 as a result of a $177,000 decrease in actuarially determined expenses due to strong asset performance of both the the pension and the other post-retirement benefit plans, a higher discount rate for valuing the benefit plan liabilities and the previously implemented soft freeze of the pension plan. June 2017 included the accrual of severance related payroll and benefit costs for 18 employees who were displaced due to changes in the customer service area. The remaining differences are related to higher bad debt expense and contracted services related to the outsourcing of the customer support services function more than offsetting reductions in operations payroll.

General taxes increased by $7,614, or 2%, as higher property taxes associated with increases in utility property offset lower payroll taxes associated with fewer employees.

Depreciation expense increased by $174,150, or 11%, on a corresponding increase in utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $133,449, more than doubling last year, due to escalation in pipeline construction activities resulting in increased investment in the Mountain Valley Pipeline ("MVP") project. As the corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"), the increased investment will result in a greater level of AFUDC income. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.

Interest expense increased by $111,292, or 24%, due to a 13% increase in total average debt to finance the Company's capital expenditures and ongoing investment in MVP and rising interest rates on the Company's variable-rate debt. The combination of the issuance of the new $8,000,000 notes in October, increased utilization of the Midstream credit facility and higher interest rates more than offset the reduction in the line-of-credit with proceeds from the equity issue in March. The weighted-average effective interest rate increased from 3.69% in the third quarter of fiscal 2017 to 3.97% during the third quarter of fiscal 2018.

Income tax expense increased by $103,342, or 30%, as much higher pre-tax income more than offset the reduction in the federal corporate income tax rate due to the passage of the Tax Act. The combined state and federal tax rate declined from 37.96% to a blended 28.84% in fiscal 2018. The effective tax rate was 29.1% for the quarter compared to 35.8% for the same

RGC RESOURCES, INC. AND SUBSIDIARIES

period last year. Additional information regarding the Tax Act and its impact on the Company is provided under the Regulatory and Tax Reform section below.

Nine Months Ended June 30, 2018:

Net income increased by $539,767 for the nine months ended June 30, 2018, compared to the same period last year due to higher revenues from the SAVE Plan, customer growth, lower operating and maintenance expenses, net of the effect of the accrued refund for excess revenues collected from customers related to the reduction in income tax expense resulting from the lower federal income tax rate.The tables below reflect operating revenues, volume activity and heating degree-days.



	Nine Months Ended June 30,
	2018		2017		Increase		Percentage
Operating Revenues
Gas Utility	$	54,675,367	$	51,346,456	$	3,328,911	6	%
Non-utility	888,227		777,966		110,261		14	%
Total Operating Revenues	$	55,563,594	$	52,124,422	$	3,439,172	7	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	6,567,993		5,305,263		1,262,730		24	%
Transportation and Interruptible	2,184,859		2,115,333		69,526		3	%
Total Delivered Volumes	8,752,852		7,420,596		1,332,256		18	%
Heating Degree Days (Unofficial)	3,948		3,213		735		23	%

Operating revenues for the nine months ended June 30, 2018 increased over the same period last year due to significant increases in natural gas deliveries and higher SAVE revenues more than offsetting the excess revenue adjustment. Total natural gas deliveries increased by 18% due to 23% more heating degree days during the period. SAVE revenues accounted for $716,382 of the increase, while revenues were reduced by $1,147,829 due to the transfer of the estimated excess revenues billed to customers to a regulatory liability. Average commodity price of gas was slightly lower compared to the same period last year.



	Nine Months Ended June 30,
	2018		2017		Increase		Percentage
Gas Utility Margin
Utility Revenues	$	54,675,367	$	51,346,456	$	3,328,911	6	%
Cost of Gas	28,175,366		24,862,147		3,313,219		13	%
Gas Utility Margin	$	26,500,001	$	26,484,309	$	15,692	—%

Regulated natural gas utility margins were nearly unchanged from the same period last year as higher SAVE revenues and increased sales from customer growth were offset by the estimated excess revenues reserve. SAVE revenues grew by $716,382 and volumetric margin, net of the adjustment for WNA, increased by $375,351. The Company deferred $1,147,829 in revenues to a regulatory liability for future refund to customers for the estimated excess revenues collected from customers due to the reduction in the federal income tax rate.

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

RGC RESOURCES, INC. AND SUBSIDIARIES



	Nine Months Ended June 30,
	2018			2017		Increase / (Decrease)
Customer Base Charge	$	9,379,506		$	9,330,860	$	48,646
Carrying Cost	400,361			406,838		(6,477		)
SAVE Plan	3,484,018			2,767,636		716,382
Volumetric	14,312,959			12,033,663		2,279,296
WNA	(43,448		)	1,860,497		(1,903,945		)
Other Gas Revenues	114,434			84,815		29,619
Excess Revenue Refund	(1,147,829		)	—		(1,147,829		)
Total	$	26,500,001		$	26,484,309	$	15,692

Operation and maintenance expenses decreased by $442,010, or 4%, from the same period last year primarily due to reductions in compensation and benefit costs and the absence of severance costs related to the outsourcing of the customer support services function last year, partially offset by a reduction in capitalized overheads, higher bad debt expense and the addition of the contracted customer service provider. Total operation and maintenance compensation declined by $144,000 in large part due to the closing of the customer service function. The labor savings were partially offset by a net increase in contracted services primarily related to the outsourced customer service provider. Employee benefit costs declined by $555,000 as a result of decreases in the actuarially determined expenses of both the the pension and the other post-retirement benefit plans. The prior period also included $135,000 in accrued severance costs. Total capitalized overheads declined by $129,000 on nearly the same level of capital expenditures subject to overhead capitalization. The decrease in capitalized overheads reflects a reduction in the rate due to lower labor and benefit costs compared to the same period last year. Bad debt expense increased by $70,000 on higher gross customer billings due to a much colder heating season. The remaining variance relates to a variety of offsetting factors.

General taxes increased by $58,451, or 4%, due to higher property taxes associated with increases in utility property partially offset by lower payroll taxes associated with fewer employees.

Depreciation expense increased by $502,449, or 11%, on higher utility plant investment.

Equity in earnings of unconsolidated affiliate increased by $295,608, or more than double last year, due to the increasing investment in the MVP project. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.

Interest expense increased by $429,122, or 31%, due to a 22% increase in total average debt outstanding and rising interest rates on the Company's variable-rate debt. The weighted-average effective interest rate increased to 3.77% during fiscal 2018.

Income tax expense declined by $700,478, or 19%, due to lower pre-tax income and the application of lower income tax rates due to the passage of the Tax Act. The effective tax rate for the first nine months of fiscal 2018 was 31.2% compared to 37.7% for the same period last year. The effective tax rate for the current period is higher than the blended rate of 28.84% due to the valuation adjustments to the net deferred tax assets of the unregulated operations. These valuation adjustments to the deferred taxes of the unregulated operations are charged to income tax expense in accordance with U.S. GAAP. Since the unregulated operations had a net deferred tax asset, the adjustment resulted in a charge to income tax expense of approximately $208,000. Excluding the $208,000 tax adjustment, the effective tax rate for the current year would have been 29%. The valuation adjustment to the net deferred tax liability of the regulated operations of Roanoke Gas was transferred to a regulatory liability as discussed in Note 4 and under the Regulatory and Tax Reform section below.

Critical Accounting Policies and Estimates

The consolidated financial statements of Resources are prepared in accordance with accounting principles generally accepted in the United States of America. The amounts of assets, liabilities, revenues and expenses reported in the Company’s financial statements are affected by accounting policies, estimates and assumptions that are necessary to comply with generally accepted accounting principles. Estimates used in the financial statements are derived from prior experience, statistical analysis and management judgments. Actual results may differ significantly from these estimates and assumptions.

The Company considers an estimate to be critical if it is material to the financial statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company's adjustments for the effect of the Tax Act includes estimates related to the revaluation of

RGC RESOURCES, INC. AND SUBSIDIARIES

deferred income tax adjustments due to the blended income tax rate and the refund of excess billings to customers pending revisions to customer billing rates to be approved by the SCC. The Company believes these adjustments to be reasonable estimates of the financial effect of the tax change based upon the best information available. These estimates will be adjusted as necessary once the SCC reviews and approves the Company's proposed rates and methodology. The Company anticipates the SCC will conduct their review of management's regulatory liabilities related to the revaluation of deferred taxes and the provision for refund for the excess billings to customers in coordination with the submission of Roanoke Gas' rate application, which will incorporate the impact of tax reform as well as changes in plant investment, operating expenses, regulatory assets and capital structure. There have been no other changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, 2017.

Asset Management

Roanoke Gas uses a third-party asset manager to manage its pipeline transportation, storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the asset manager pays Roanoke Gas a monthly utilization fee. In March 2018, Roanoke Gas executed a new three-year asset management agreement with the same asset manager under terms similar to the expired contract.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the "LLC"). The purpose of the LLC is to construct and operate the MVP, a 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 a liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company's ability to serve its customers. A third pipeline would reduce the risk from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.

On October 13, 2017, FERC issued the MVP Certificate of Public Convenience and Necessity; and, since January 2018, FERC has issued several Notices to Proceed ("NTP"), which granted the LLC permission to begin construction activities. The LLC also received the necessary federal permits and the required Virginia and West Virginia environmental agency permits.

Since construction began, the LLC has encountered various challenges to the project including pipeline protesters and legal challenges to various federal and state permits. On August 3, 2018, due to an earlier U.S. Fourth Circuit Court of Appeals decision regarding pipeline construction in the Jefferson National Forest, FERC issued a stop work order directing that all construction activity cease immediately, with the exception of any measures deemed necessary to ensure stabilization of the right-of-way and work areas. The LLC is working with all related regulatory entities and judicial bodies to resolve these issues.

Due to the legal challenges, the LLC is evaluating its construction plan for the MVP on a daily basis and moved its target in-service date from the fourth quarter of calendar 2018 to the first quarter of calendar 2019.

Initially, the total project cost was estimated to be $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution was expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments were for the acquisition of land and materials related to the construction of the pipeline and other pre-construction costs. As construction activities have progressed, more significant cash draws have been required. When the LLC managing partner recently revised the targeted in-service date, the estimated cost of the pipeline increased to between $3.5 billion and $3.7 billion with Midstream's cash requirement increasing to between $35 million and $37 million. Funding for the investment in the LLC is provided through the Midstream credit facility, as amended, whereby Midstream may borrow up to a total of $38 million through 2020. The increased limits provide Midstream with additional funding resources in the event the cost of its investment in the LLC exceeds projections. See Note 7 for more information on the borrowing facility.

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.

RGC RESOURCES, INC. AND SUBSIDIARIES

On April, 11, 2018, the LLC announced the MVP Southgate project ("Southgate"), which will be a 70 mile pipeline extending from the Mountain Valley Pipeline mainline in Virginia to delivery points in Rockingham and Alamance counties in North Carolina. The Southgate in-service date is targeted for the end of 2020. Midstream will be an investor in this project.

Regulatory and Tax Reform

Based on its evaluation of the effects of tax reform as discussed below and the changes in plant investment, operating expenses, regulatory assets and capital structure, management plans to file a rate application to incorporate the effect of these changes into customer billing rates. As part of the rate application, revenues currently collected under the SAVE Plan mechanism through December 31, 2018 will be incorporated into the revised customer base charge and volumetric rates rather than reflected as a separate rider. The Company currently anticipates filing its application in September 2018 with new rates expected to be in place in January 2019, subject to refund based on review of the Company's request.

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

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

As a result of the tax rate change, the Company is impacted by both an adjustment to the valuation of deferred tax assets and liabilities and a lower tax rate used in calculating net income. ASC 740, Income Taxes, requires entities to revalue their deferred tax assets and liabilities based on changes in tax rates and record the change in income tax expense. The Company's deferred income taxes had been calculated based on a 34% federal tax rate and have been adjusted to the new federal tax rate of 21%. In order to fairly value the deferred taxes at the appropriate rates, the Company had to project deferred activity for the balance of the fiscal year to estimate the impact to tax expense for the valuation adjustment. The Company is utilizing the guidance provided under the SEC Staff Accounting Bulletin ("SAB") 118 and recording reasonable estimates of the effect of the tax rate change on its deferred tax assets and liabilities and the corresponding impact to income tax expense and regulatory liabilities.

The accounting guidance under ASC 740 - Income Taxes requires the adjustment to deferred income taxes due to the revaluation be recorded as a component of income tax expense from continuing operations. Furthermore, the revaluation of deferred taxes associated with components of other comprehensive income is also recorded as a component of income tax expense and not as an adjustment to other comprehensive income. However, the deferred income taxes of Roanoke Gas were accumulated based on customer billing rates derived utilizing a 34% federal income tax rate assumption. Therefore, any reduction in the net deferred tax liabilities should be refunded to its customers and not reflected as an immediate adjustment to income tax expense. The Company reclassified the revaluation adjustments associated with Roanoke Gas' deferred income taxes to a regulatory liability.

As discussed above, Roanoke Gas' billing rates include a provision for federal income taxes at a 34% rate. Since the beginning of the current fiscal year, the Company has been recovering from its customers at the higher 34% tax rate as opposed to the blended 24.3% federal tax rate currently in effect. On January 8, 2018, the SCC issued a directive requiring the accrual of a regulatory liability for the excess revenues collected from Roanoke Gas customers. The directive remains in place until such time as the SCC approves and the Company implements, lower billing rates incorporating the lower federal income tax rate.

For the nine-months ended June 30, 2018, the Company recorded an estimated reduction to revenue and established a regulatory liability in the amount of $1,147,829 for the excess revenues collected from customers. On an annualized basis, the reduction for the excess revenues included in the Company's billing rates should approximate the reduction in income tax expense resulting from the lower federal income tax rate.

The estimated refund will be revised as necessary once the SCC reviews and approves the adjustment calculations and methodology for determining the refund. The method, amount and timing of the refunds will ultimately be determined by the SCC in connection with their review of the rate application.

RGC RESOURCES, INC. AND SUBSIDIARIES

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

On June 29, 2018, the Company filed its 2019 SAVE Plan application with the SCC. In this application, the Company is requesting a modification of the SAVE Plan year from a calendar year to the Company's fiscal year. The revenue requirement in the application is approximately $365,000 for the projected nine-month investment related to the replacement of pre-1973 plastic pipe.

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 approving implementation of an incentive mechanism, whereby the Company would share the utilization fee with its customers. Under the incentive mechanism, customers would receive the initial $700,000 of the utilization fee collected through reduced gas costs and thereafter every additional dollar received during the annual period would be split with 25% to the Company and 75% to its customers. The SCC order provided retroactive application of the incentive mechanism to April 1, 2018. Therefore, the Company did not recognize any amount under the incentive mechanism during the current quarter as the first $700,000 was applied to reduce gas costs for customers. Beginning in July 2018, the $700,000 threshold for the current asset management year will have been met, and the Company will begin recognizing its portion of the utilization fee.

On May 7, 2018, the SCC granted the Company's motion to resume its proceeding for the application of a Certificate of Public Convenience and Necessity to include the remaining portions of Franklin County, Virginia into its authorized natural gas service territory. The Company anticipates the SCC will complete its review of the application over the next few months and issue a decision sometime thereafter.

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 $1,130,862 for the nine-month period ended June 30, 2018, compared to a $120,564 increase for the same period last year. The following table summarizes the sources and uses of cash:



	Nine Months Ended June 30,
	2018			2017
Cash Flow Summary Nine Months Ended
Net cash provided by operating activities	$	13,859,063		$	15,751,066
Net cash used in investing activities	(21,296,642		)	(18,240,994		)
Net cash provided by financing activities	8,568,441			2,610,492
Increase in cash and cash equivalents	$	1,130,862		$	120,564

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

Cash flow provided by operations is primarily driven by net income, depreciation, reductions in natural gas storage inventory and increases in accounts receivable during the first nine months of the fiscal year. Cash flow from operating activities decreased from the same period last year by $1,892,003, primarily due to a net reduction in over-collections during the current year compared to an increase in the prior year partially offset by a greater reduction in gas in storage balances. The net reduction in over-collections of gas costs resulted from stable commodity prices on natural gas during the year and near normal

RGC RESOURCES, INC. AND SUBSIDIARIES

weather that resulted in actual gas costs nearly matching projected costs used in the PGA factor. In addition, the current year also reflects the refunding of the prior year over-collected balance, resulting in the lower over-collected balance. Total gas storage balances declined by a greater amount during the current fiscal year due to a combination of lower ending storage volumes associated with the colder winter heating season and lower natural gas commodity prices on deliveries into storage during the current year compared to the corresponding period last year. A summary of the cash provided by operations is listed below:



	Nine Months Ended June 30,
Cash Flow From Operating Activities:	2018			2017		Increase / (Decrease)
Net income	$	6,612,746		$	6,072,979	$	539,767
Depreciation	5,297,337			4,793,270		504,067
Increase (decrease) in over-collections	(444,961		)	2,348,534		(2,793,495		)
Decrease in gas in storage	2,648,167			1,991,510		656,657
Other	(254,226		)	544,773		(798,999		)
Net Cash Provided by Operations	$	13,859,063		$	15,751,066	$	(1,892,003	)

Investing activities are generally composed of expenditures related to investment in the Company's utility plant projects, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and distribution system facilities, expanding 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 and replacement of a natural gas transfer station. In addition, the Company is constructing two interconnect stations to tie into the Mountain Valley Pipeline which will provide additional gas supply to the Company's distribution system as well as provide access to currently unserved areas. Two large system reinforcement projects are currently underway to provide additional capacity to meet the natural gas requirements for existing customers as well as provide natural gas access to a new industrial park. Total capital expenditures for the first nine months were $16.1 million, which represented a nearly $400,000 reduction from the same period last year. The prior year included expenditures related to the installation of an automated meter reading system ("AMR") that was fully operational in fiscal 2017. Current projections indicate that total 2018 capital expenditures should exceed last year's levels.

Investing cash flows also includes the Company's continued funding of its participation in the MVP, with a total cash investment of $5,250,680 for the nine months ended June 30, 2018 compared to $1,803,100 for the corresponding period last year. With FERC approval and the issuance of state permits, pipeline construction activities are underway. The Company will increase its utilization of the Midstream credit facility to meet the accelerating funding requirements.

Financing activities generally consist of long-term notes payable and line-of-credit borrowings and repayments, issuance of stock and the payment of dividends. Cash flows provided by financing activities were $8,568,441 for the current period compared to $2,610,492 for the same period last year. The increase in financing cash flows is attributable to higher non line-of-credit borrowings and proceeds from an equity issue. The Company borrowed $5,537,000 under the Midstream credit facility compared to $1,924,000 for the same period last year. In addition, Roanoke Gas issued $8,000,000 in notes in October 2017 compared to a $7,000,000 bank note issued during the prior year. These notes were used to refinance part of the line-of-credit balance that provided capital expenditure bridge financing. The Company also realized more than $15,000,0000 in net proceeds from the issuance of 700,000 shares of common stock in March 2018. $15,000,000 of the equity issue was invested directly into Roanoke Gas to supplement the funding of its infrastructure improvement program and pay down the balance on its line-of-credit. Based on current projections for capital expenditures as well as working capital funding needs, the Company anticipates to begin utilizing the line-of-credit again by the 4th quarter of fiscal 2018. Resources long-term capitalization ratio is 58.1% equity and 41.9% debt at June 30, 2018.

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

RGC RESOURCES, INC. AND SUBSIDIARIES

On March 26, 2018, Roanoke Gas entered into a new unsecured revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2020, replacing the prior two-year agreement scheduled to expire on March 31, 2019. The new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance on the note. The agreement also maintains the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The total available borrowing limits during the term of the agreement range from $2,000,000 to $25,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are generally considered to be non-current.

On April 11, 2018, Midstream entered into the First Amendment to Credit Agreement ("Amendment") and amendments to the related Promissory Notes ("Notes") originally issued in December 2015. Under the provisions of the Amendment, the total borrowing limits under the Notes increased to $38,000,000 with a reduction in the interest rate to 30-day LIBOR plus 135 basis points. Furthermore, the Amendment removed the previous requirement for Midstream to provide $5,000,000 in funding outside of the Notes and now allows for the entire investment in the LLC to be funded through these amended Notes. The increased limits provide Midstream with additional funding resources in the event the cost of its investment in the LLC exceeds current projections.

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, 2018, the Company had no outstanding balance under its variable rate line-of-credit with an average balance outstanding during the nine-month period of $8,197,148. The Company also had $11,849,200 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, 2018 would have resulted in an increase of approximately $131,000 in interest expense. 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, 2018, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 1,641,236 decatherms of gas in storage, including LNG, at an average price of $3.08 per decatherm, compared to 1,711,610 decatherms at an average price of $3.18 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, 2018, 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, 2018.

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, 2018, 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, 2017 other than the risks described below.

The regulatory approval process for the construction of the Mountain Valley Pipeline could impact the LLC's ability to obtain authorizations necessary for the completion of the project.

Any significant delays in the regulatory approval process for the Mountain Valley Pipeline ("MVP") project could increase costs and negatively impact the scheduled in-service date, which in turn could adversely affect the ability of the LLC and its owners, including Midstream, to achieve the expected investment return. For example, on August 3, 2018, due to an earlier U.S. Fourth Circuit Court of Appeals decision regarding pipeline construction in the Jefferson National Forest, FERC issued a stop work order directing that all pipeline construction activity cease immediately. FERC was requesting that both the U.S. Forest Service and the Bureau of Land Management provide further information and clarification in support of their prior approvals of the related permits. Failure to resolve this issue and other similar litigation or regulatory requirements could adversely affect Resources' financial condition and results of operations.

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		First Amendment to Credit Agreement between RGC Midstream, LLC and the lenders Union Bank & Trust and Branch Bank and Trust dated April 11. 2018 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on April 12, 2018)
10.2		Amended and Restated Note in the principal amount of $22,800,000 in favor of Union Bank & Trust due December 29, 2020 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on April 12, 2018)
10.3		Amended and Restated Note in the principal amount of $15,200,000 in favor of Branch Banking and Trust due December 29, 2020 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on April 12, 2018)
10.4		Change in Control Agreement between RGC Resources, Inc and Mr. John S. D'Orazio effective May 1, 2018 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 1, 2018)
10.5		Change in Control Agreement between RGC Resources, Inc and Mr. Paul W. Nester effective May 1, 2018 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on May 1, 2018)
10.6		Change in Control Agreement between RGC Resources, Inc and Mr. Robert L. Wells, II effective May 1, 2018 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on May 1, 2018)
10.7		Change in Control Agreement between RGC Resources, Inc and Mr. Carl J. Shockley, Jr. effective May 1, 2018 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on May 1, 2018)
10.8		Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC dated April 6, 2018 (incorporated by reference to Exhibit 10.1 on Form 10Q/A as filed on July 3, 2018)
10.9		Guaranty Agreement by RGC Resources, Inc. in favor of Mountain Valley Pipeline, LLC (incorporated by reference to Exhibit 10.2 on Form 10Q as filed on May 7, 2018)
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, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at June 30, 2018 and September 30, 2017, (ii) Condensed Consolidated Statements of Income for the three months and nine months ended June 30, 2018 and 2017; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and nine months ended June 30, 2018 and 2017; (iv) Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2018 and 2017, and (v) 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, 2018	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Secretary, Treasurer and CFO