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,~~December 31, 2017

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~~January 31, ~~2017~~2018
Common Stock, $5 Par Value		~~7,232,482~~7,263,289

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	Unaudited						Unaudited
	June 30, 2017			September 30, 2016			December 31, 2017			September 30, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	763,816		$	643,252		$	334,278		$	69,640
Accounts receivable (less allowance for uncollectibles of $282,829 and $76,934, respectively)	4,659,087			3,478,983
Accounts receivable (less allowance for uncollectibles of $200,938 and $99,456, respectively)							10,895,194			3,492,703
Materials and supplies	983,899			824,139			1,072,097			1,021,191
Gas in storage	5,445,275			7,436,785			6,906,656			7,701,894
Prepaid income taxes	—			1,550,836			798,414			1,796,825
Interest rate swap							46,847			26,777
Other	1,273,224			1,548,329			1,828,144			1,576,574
Total current assets	13,125,301			15,482,324			21,881,630			15,685,604
UTILITY PROPERTY:
In service	199,152,544			185,577,286			206,193,289			204,223,714
Accumulated depreciation and amortization	(58,895,489		)	(56,156,287		)	(60,653,163		)	(59,765,987		)
In service, net	140,257,055			129,420,999			145,540,126			144,457,727
Construction work in progress	4,709,968			2,707,139			6,369,011			3,470,244
Utility plant, net	144,967,023			132,128,138			151,909,137			147,927,971
OTHER ASSETS:
Regulatory assets	14,504,029			14,332,451			11,810,238			11,796,260
Investment in unconsolidated affiliate	5,704,091			3,496,404			10,095,214			7,445,106
Fair value of marked-to-market transactions	118,606			—
Interest rate swap							132,735			90,066
Other	115,707			113,532			452,365			190,064
Total other assets	20,442,433			17,942,387			22,490,552			19,521,496
TOTAL ASSETS	$	178,534,757		$	165,552,849		$	196,281,319		$	183,135,071

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	Unaudited						Unaudited
	June 30, 2017			September 30, 2016			December 31, 2017			September 30, 2017
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Line-of-credit	$	—		$	14,556,785		$	54,377		$	—
Dividends payable	1,048,710			970,244			1,125,677			1,050,281
Accounts payable	5,730,734			5,345,575			7,229,538			5,122,899
Capital contributions payable	402,589			287,794			2,323,821			1,055,504
Customer credit balances	715,139			1,605,608			1,004,059			1,220,578
Income taxes payable	552,148			—
Customer deposits	1,532,074			1,627,105			1,512,915			1,471,960
Accrued expenses	2,485,160			3,194,255			2,047,301			3,006,936
Over-recovery of gas costs	3,258,221			909,687			2,116,450			1,438,074
Rate refund							462,442			—
Total current liabilities	15,724,775			28,497,053			17,876,580			14,366,232
LONG-TERM DEBT:
Notes payable	42,820,200			33,896,200			53,076,200			43,812,200
Line-of-credit	10,516,426			—			17,000,000			17,791,760
Less unamortized debt issuance costs	(252,117		)	(260,149		)	(282,417		)	(291,949		)
Long-term debt net of unamortized debt issuance costs	53,084,509			33,636,051			69,793,783			61,312,011
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	5,867,216			5,682,556			6,136,712			6,069,993
Regulatory cost of retirement obligations	10,014,380			9,348,443			10,259,624			10,055,189
Benefit plan liabilities	13,557,156			13,763,820			7,683,080			8,214,326
Deferred income taxes	20,615,021			18,957,854			11,488,231			23,076,848
Regulatory liability - deferred income taxes							11,742,274			—
Total deferred credits and other liabilities	50,053,773			47,752,673			47,309,921			47,416,356
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,231,535 and 7,182,434, respectively	36,157,675			23,941,445
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,251,014 and 7,240,846, respectively							36,255,070			36,204,230
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—			—			—
Capital in excess of par value	182,031			9,509,548			528,154			292,485
Retained earnings	25,636,416			24,713,310			25,679,679			24,746,021
Accumulated other comprehensive loss	(2,304,422		)	(2,497,231		)	(1,161,868		)	(1,202,264		)
Total stockholders’ equity	59,671,700			55,667,072			61,301,035			60,040,472
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	178,534,757		$	165,552,849		$	196,281,319		$	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,~~DECEMBER 31, 2017 AND 2016

UNAUDITED


	Three Months Ended June 30,				Nine Months Ended June 30,				Three Months Ended December 31,
	2017		2016		2017		2016		2017		2016
OPERATING REVENUES:
Gas utilities	$	11,171,499	$	11,017,281	$	51,346,456	$	48,372,615	$	18,519,994	$	18,512,333
Other	264,325		277,916		777,966		710,411		236,057		276,252
Total operating revenues	11,435,824		11,295,197		52,124,422		49,083,026		18,756,051		18,788,585
COST OF SALES:
Gas utilities	4,679,047		4,833,604		24,862,147		23,037,896		9,561,406		9,246,852
Other	122,375		149,253		407,238		345,405		121,210		150,828
Total cost of sales	4,801,422		4,982,857		25,269,385		23,383,301		9,682,616		9,397,680
GROSS MARGIN	6,634,402		6,312,340		26,855,037		25,699,725		9,073,435		9,390,905
OTHER OPERATING EXPENSES:
Operations and maintenance	3,294,939		3,060,435		9,880,293		9,868,164		3,197,111		3,391,828
General taxes	450,528		413,711		1,372,870		1,281,312		466,322		441,074
Depreciation and amortization	1,560,728		1,384,844		4,702,185		4,154,533		1,734,878		1,575,728
Total other operating expenses	5,306,195		4,858,990		15,955,348		15,304,009		5,398,311		5,408,630
OPERATING INCOME	1,328,207		1,453,350		10,899,689		10,395,716		3,675,124		3,982,275
Equity in earnings of unconsolidated affiliate	111,626		40,562		289,791		95,945		148,811		84,540
Other expense, net	8,738		39,151		23,020		71,460		16,132		3,712
Interest expense	472,300		396,304		1,400,301		1,220,600		612,645		458,521
INCOME BEFORE INCOME TAXES	958,795		1,058,457		9,766,159		9,199,601		3,195,158		3,604,582
INCOME TAX EXPENSE	343,233		431,389		3,693,180		3,538,296		1,135,696		1,372,364
NET INCOME	$	615,562	$	627,068	$	6,072,979	$	5,661,305	$	2,059,462	$	2,232,218
BASIC EARNINGS PER COMMON SHARE	$	0.09	$	0.09	$	0.84	$	0.79	$	0.28	$	0.31
DILUTED EARNINGS PER COMMON SHARE	$	0.08	$	0.09	$	0.84	$	0.79	$	0.28	$	0.31
DIVIDENDS DECLARED PER COMMON SHARE	$	0.1450	$	0.1350	$	0.4350	$	0.4050	$	0.1550	$	0.1450

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,~~DECEMBER 31, 2017 AND 2016

UNAUDITED


	Three Months Ended June 30,					Nine Months Ended June 30,				Three Months Ended December 31,
	2017			2016		2017		2016		2017			2016
NET INCOME	$	615,562		$	627,068	$	6,072,979	$	5,661,305	$	2,059,462		$	2,232,218
Other comprehensive income, net of tax:
Interest rate swap	(25,053		)	—		73,583		—		44,645			95,128
Defined benefit plans	39,742			34,289		119,226		102,867		(4,249		)	39,742
OTHER COMPREHENSIVE INCOME, NET OF TAX	14,689			34,289		192,809		102,867		40,396			134,870
COMPREHENSIVE INCOME	$	630,251		$	661,357	$	6,265,788	$	5,764,172	$	2,099,858		$	2,367,088

See notes to condensed consolidated financial statements.

RGC RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE ~~NINE-MONTH~~THREE-MONTH PERIODS

ENDED ~~JUNE 30,~~DECEMBER 31, 2017 AND 2016

UNAUDITED


	Nine Months Ended June 30,						Three Months Ended December 31,
	2017			2016			2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6,072,979		$	5,661,305		$	2,059,462		$	2,232,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	4,793,270			4,245,223			1,765,779			1,606,090
Cost of removal of utility plant, net	(236,292		)	(291,620		)	(121,384		)	(97,800		)
Stock option grants	73,780			64,640			—			12,297
Equity in earnings of unconsolidated affiliate	(289,791		)	(95,945		)	(148,811		)	(84,540		)
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately	5,337,120			5,951,846			(5,513,739		)	(5,781,253		)
Net cash provided by operating activities	15,751,066			15,535,449
Net cash used in operating activities							(1,958,693		)	(2,112,988		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(16,451,865		)	(12,558,509		)	(4,306,651		)	(4,438,642		)
Investment in unconsolidated affiliate	(1,803,100		)	(2,272,576		)	(1,232,980		)	(485,747		)
Proceeds from disposal of equipment	13,971			543			244			1,560
Net cash used in investing activities	(18,240,994		)	(14,830,542		)	(5,539,387		)	(4,922,829		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	8,924,000			2,596,200			9,264,000			7,508,000
Borrowings under line-of-credit agreement	31,170,307			26,452,983			11,888,529			11,501,201
Repayments under line-of-credit agreement	(35,210,666		)	(27,666,149		)	(12,625,912		)	(11,732,610		)
Debt issuance expenses	(16,675		)	(101,619		)	—			(16,675		)
Proceeds from issuance of stock (49,101 and 54,255 shares, respectively)	810,689			774,175
Proceeds from issuance of stock (10,168 and 17,122 shares, respectively)							286,509			278,968
Cash dividends paid	(3,067,163		)	(2,840,898		)	(1,050,408		)	(970,244		)
Net cash provided by (used in) financing activities	2,610,492			(785,308		)
Net cash provided by financing activities							7,762,718			6,568,640
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	120,564			(80,401		)	264,638			(467,177		)
BEGINNING CASH AND CASH EQUIVALENTS	643,252			985,234			69,640			643,252
ENDING CASH AND CASH EQUIVALENTS	$	763,816		$	904,833		$	334,278		$	176,075
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	1,598,629		$	1,435,553		$	814,061		$	730,163
Income taxes paid	51,000			181,000			—			—

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,~~December 31, 2017 and the results of its operations, cash flows and comprehensive income for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2017 and 2016. The results of operations for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2017 are not indicative of the results to be expected for the fiscal year ending September 30, ~~2017~~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 made 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, ~~2016.~~2017. The September 30, ~~2016~~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.

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

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, ~~2016.~~2017. Newly adopted and newly issued accounting standards are discussed below.

Recently Issued or Adopted Accounting Standards

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) that affects any entity that enters into contracts with customers for the transfer of goods or services or transfer of non-financial assets. This guidance supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies the performance obligation. 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.

~~As of June 30, 2017, the Company is identifying sources of revenue and evaluating the effect that the revenue guidance will have on financial results and disclosures.~~ The FASB continues to issue subsequent guidance under ASC No. 606 to ~~provide~~ further ~~clarification of~~clarify the original ASU. In addition, the Company is also monitoring the activity of the Power and Utilities Task Force. The Task Force was formed by the American Institute of Certified Public Accountants ("AICPA") ~~in an effort~~ to provide industry-specific guidance. Implementation issues identified by the Task Force include accounting for contributions in aid of construction and assessing collectability of customer accounts when regulated mechanisms exist to allow recovery of uncollected accounts from ratepayers. ~~The Company will consider all current and future guidance in before determining how best to implement the new revenue recognition standard.~~

~~Although Management has not completed its evaluation~~As of ~~all the issued guidance under ASC No. 606, currently~~December 31, 2017, the Company ~~does~~continues identifying sources of revenue and evaluating the effect that the revenue guidance will have on financial results and disclosures. Based on the review of customer contracts to date, the Company is not ~~expect it to have~~anticipating a material ~~effect on~~impact to its financial position, results of operations or cash ~~flows. However,~~flows upon adoption; however, the ~~disclosure requirements under ASU 2014-09 could be~~

Company does anticipate the potential for significant new disclosures as a result of the guidance. Because of ongoing internal analysis and the continued activities of the FASB and other related implementation efforts specific to the ~~Company.~~rate-regulated natural gas industry, early adoption is not expected.

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. Management ~~is in~~has not completed its evaluation of the ~~process of compiling an~~new guidance. However, the Company has completed its inventory of ~~all~~ leases that fall under the requirements of ASU 2016-02. The Company has very few agreements that fall under the prior definition of leases; however, management is reviewing other agreements that may fall within the scope of ASU 2016-02. The Companyand does not currently expect the new guidance to have a material effect on its financial position, results of operations or cash flows.

~~In March 2016, the FASB issued ASU 2016-09,~~ ~~Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting~~. The guidance simplifies several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The new guidance is effective for the Company for the annual reporting period ending September 30, 2018 and interim periods within that annual period. Early adoption is permitted. The Company adopted this ASU during the quarter ended September 30, 2016. This ASU had no effect on the financial statements at the time of adoption; however, as the application of the APIC pool is eliminated, the Company will recognize all excess tax benefits and deficiencies associated with the exercise of stock options in income tax expense rather than as an offset to additional paid in capital.

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 and from allowed regulatory accounting. 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 is in the process of evaluating the new ~~guidance from this ASU.~~guidance. The regulatory body in the Company's service jurisdiction requires the capitalization of all cost components included in net benefit costs. As a result, the Company may have to establish regulatory assets for those costs now excluded from capitalization under this ASU. The Company has begun discussions with its regulatory body, the State Corporation Commission of Virginia, regarding the expected treatment of those costs. Although the ultimate disposition of these other components of net periodic benefit costs has not been determined, management expects the new guidance may have a material effect on the Company's consolidated financial statements when adopted.

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.

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 Split~~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 ~~17, 2017, Resources Board~~1, 2018. As the Company operates on a fiscal year, the Company will have a transition or blended rate of ~~Directors approved a three-for-two stock split~~24.3% determined based on the number of days of the Company's ~~issued~~fiscal year at 34% and ~~outstanding common stock. The stock split was effected~~the number of days in the ~~form~~year at 21%.

Under the provisions of a 50% stock dividend entitling each shareholder to receive one additional share of common stock for every two shares owned. The stock dividend was payable March 1, 2017 to shareholders of record on February 15, 2017. AsASC 740 - Income Taxes, the ~~par value~~deferred tax assets and liabilities of the ~~common stock remained at $5 per share, the~~ Company reclassified $10,025,546 from "Capital in excess of par value" and $2,004,244 from "Retained earnings" to "Common stock" associated with the issuance of 2,405,958 shares. Corresponding prior period amounts, including share and per share data, have been restated retrospectivelymust be revalued to reflect the ~~50% stock dividend.~~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. The Company has 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 3, while $208,288 was charged to income tax expense 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.


3.	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 2, 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 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 ~~June 30,~~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. As of December 31, 2017, the Company ~~filed with~~recorded an estimated reduction to revenue and established a regulatory liability in the ~~SCC its SAVE (Steps to Advance Virginia's Energy) Plan and Rider application. The SAVE Plan provides a mechanism for~~amount of $462,442 reflecting the ~~Company to recover the related depreciation and expenses and a return on rate base~~excess revenue collected from customers since October 1, 2017. This estimated refund of ~~the additional capital investment~~excess revenue as well as estimated regulatory liability related to the ~~modernization of aging natural gas infrastructure without the filing of a formal application for an increase~~excess deferred taxes on Roanoke Gas will be adjusted as necessary and reflected in non-gas base rates. Under the current application, the Company submitted its report for collecting the shortfall in SAVE revenues collected under the 2016 SAVE Plan and proposed new 2018 SAVE rates to be implemented for the ongoing investment in SAVE Plan projects. The Company anticipatesfuture financial statements once the SCC ~~to complete its review~~reviews and approves the Company's calculations and methodology.

The method and timing of the ~~application over~~refunds of both the ~~next few months. The Company continues to bill its customers for SAVE~~excess deferred income taxes and the excess revenues ~~associated with its 2017 SAVE Plan.~~will be determined by the SCC.

RGC RESOURCES, INC. AND SUBSIDIARIES


4.	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. ~~Subject to approval by the~~The pipeline has received Federal Energy Regulatory Commission ~~the pipeline~~("FERC") approval and is ~~targeted~~scheduled to bebegin construction in ~~service by late~~early 2018.

The total project cost is estimated to be approximately $3.5 billion. The Company's 1% equity interest in the LLC will require a total estimated cash investment of approximately $35 million, by periodic capital contributions throughout the design and construction phases of the project. ~~Midstream held an approximate $5.7 million equity method investment in the LLC at June 30, 2017.~~ 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,~~December 31, 2017, the Company had ~~$402,589~~$2,323,821 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,~~December 31, 2017, with a corresponding increase to Investment in ~~Unconsolidated Affiliate.~~unconsolidated affiliate. Related to capital contributions payable, there was a non-cash ~~$114,795~~$1,268,317 increase in the Investment in ~~Unconsolidated Affiliate~~unconsolidated affiliate in the ~~nine~~three months ended

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

~~June 30,~~ December 31, 2017. Initial funding for Midstream's investment in the LLC is 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, 2017		September 30, 2016		December 31, 2017		September 30, 2017
Other Assets:
Investment in unconsolidated affiliate	$	5,704,091	$	3,496,404	$	10,095,214	$	7,445,106


Current Liabilities:
Capital contributions payable	$	402,589	$	287,794	$	2,323,821	$	1,055,504


	Three Months Ended				Nine Months Ended				Three Months Ended
Income Statement Location of Other Investments:	June 30, 2017		June 30, 2016		June 30, 2017		June 30, 2016		December 31, 2017		December 31, 2016
Equity in earnings of unconsolidated affiliate	$	111,626	$	40,562	$	289,791	$	95,945	$	148,811	$	84,540


5.	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 ~~with Branch Banking & Trust~~ as discussed in Note 6. Effective November 1, 2017, the swap agreement ~~converts~~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 ~~sheets under the caption of "Fair value of marked-to-market transactions":~~sheet:

RGC RESOURCES, INC. AND SUBSIDIARIES



	~~June 30, 2017~~	~~September 30, 2016~~
~~Derivative designated as hedging instrument:~~
~~Interest rate swap~~	~~$118,606~~	—



	December 31, 2017	September 30, 2017
Derivative designated as hedging instrument:
Current assets:
Interest rate swap	$46,847	$26,777

Other assets:
Interest rate swap	$132,735	$90,066

Total derivatives designed as hedging instruments	$179,582	$116,843

The table in Note 7 reflects the effect on income and other comprehensive income of the Company's cash flow hedge.


6.	Long-Term Debt

On October 2, 2017, Roanoke Gas issued ten-year unsecured notes in the 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 27, 2017, Roanoke Gas entered into a new unsecured line-of-credit agreement. This new line-of-credit agreement replaced the agreement which expired on March 31, 2017. The expired agreement was for a term of one year and all amounts drawn against that agreement were considered to be current liabilities. The ~~new~~current line-of-credit agreement is for a two-year term expiring March 31, 2019. 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.

~~Except~~The agreement provides for ~~the two-year term, the new agreement maintains the same~~a variable interest rate based on 30-day LIBOR plus 100 basis points and an availability fee of 15 basis ~~points as the expired agreement.~~points. The ~~new~~ agreement ~~also maintains the~~includes multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize borrowing costs. The

Company's total available borrowing limits during the term of the ~~new~~ agreement range from $10,000,000 to $30,000,000. As the available borrowing limit drops to $17,000,000 on March 1, 2018, $54,377 of the balance outstanding was reclassified to current at December 31, 2017. The Company ~~anticipates being able~~has begun discussions with the financial institution to extend ~~or replace~~ the ~~line-of-credit upon expiration.~~current agreement for an additional year during the second fiscal quarter.

~~On November 1, 2016,~~ Roanoke Gas ~~entered into~~has a 5-year unsecured note ~~with Branch Banking & Trust~~ in the principal amount of $7,000,000. ~~The~~This note is variable rate with interest based on 30-day LIBOR plus 90 basis ~~points. In addition, Roanoke Gas also entered into~~points with the interest rate hedged by a swap agreement ~~to convert~~which converts the variable rate debt into a fixed-rate instrument with an annual interest rate of 2.30%. The swap agreement is not effective until November 1, 2017, with the monthly interest rate on the note floating until the swap period begins. The proceeds from the note were used to convert a portion of the Company's line-of-credit balance into longer-term financing.

Midstream has two unsecured Promissory Notes ("Notes") which provide up to a total of $25 million in borrowing limits over a period of 5 years, with an interest rate of 30-day LIBOR plus 160 basis points. Midstream issued the Notes in December 2015 to provide financing for capital contributions in respect of its 1% interest in the LLC. In accordance with the terms of the Agreement, at such point in time as Midstream has borrowed $17.5 million under the Notes, Midstream is required to provide the next $5 million towards its capital contributions to the LLC. Once Midstream has completed its $5 million in contributions, it may resume borrowing under the Notes up to the $25 million limit.

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~~consolidated long-term indebtedness to not more than 65% of ~~Consolidated Total Capitalization and Priority Indebtedness~~total capitalization. All of the debt agreements, except for the line-of-credit, provide for priority indebtedness to not ~~more than~~exceed 15% of ~~Consolidated Total Assets.~~consolidated total assets.

Long-term debt consists of the following:

June 30, 2017 September 30, 2016
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
$ 166,533
$ 30,500,000
$ 173,773
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021 7,000,000
14,451
—
—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.60%, due December 29, 2020 5,320,200
71,133
3,396,200
86,376
Total notes payable $ 42,820,200
$ 252,117
$ 33,896,200
$ 260,149
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2019 $ 10,516,426
$ —
$ —
$ —
Total long-term debt $ 53,336,626
$ 252,117
$ 33,896,200
$ 260,149



	December 31, 2017					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		$	161,706	$	30,500,000	$	164,119
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000			12,784		7,000,000		13,618
Unsecured term notes payable, at 3.58% due on October 2, 2027	8,000,000			46,956		—		48,160
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.60%, due December 29, 2020	7,576,200			60,971		6,312,200		66,052
Total notes payable	$	53,076,200		$	282,417	$	43,812,200	$	291,949
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2019	$	17,054,377		$	—	$	17,791,760	$	—
Current portion of line-of-credit	(54,377		)	—		—		—
Total long-term debt	$	70,076,200		$	282,417	$	61,603,960	$	291,949


7.	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 December 31, 2017
Interest rate swap:
Unrealized gains	$	61,581		$	(17,760	)	$	43,821
Transfer of realized losses to interest expense	1,158			(334		)	824
Net interest rate swap	62,739			(18,094		)	44,645
Defined benefit plans:
Amortization of actuarial gains	(5,971		)	1,722			(4,249		)
Other comprehensive income	$	56,768		$	(16,372	)	$	40,396
Three Months Ended December 31, 2016
Interest rate swap:
Unrealized gains	$	153,334		$	(58,206	)	$	95,128
Defined benefit plans:
Amortization of actuarial losses	64,058			(24,316		)	39,742
Other comprehensive income	$	217,392		$	(82,522	)	$	134,870

Before-Tax
Amount

Tax
(Expense)
or Benefit

Net-of-Tax
Amount
Three Months Ended June 30, 2017
Interest rate swaps:
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
Three Months Ended June 30, 2016
Interest rate swaps:
Unrealized losses $ —
$ —
$ —
Defined benefit plans:
Amortization of actuarial losses 55,268
(20,979 ) 34,289
Other comprehensive income $ 55,268
$ (20,979 ) $ 34,289

Before-Tax
Amount

Tax
(Expense)
or Benefit

Net-of-Tax
Amount
Nine Months Ended June 30, 2017
Interest rate swaps:
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
Nine Months Ended June 30, 2016
Interest rate swaps:
Unrealized losses $ —
$ —
$ —
Defined benefit plans:
Amortization of actuarial losses 165,804
(62,937 ) 102,867
Other comprehensive income $ 165,804
$ (62,937 ) $ 102,867

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

RGC RESOURCES, INC. AND SUBSIDIARIES

Reconciliation of Other Accumulated Comprehensive Income (Loss)

Accumulated
Other
Comprehensive
Income (Loss)
Balance at September 30, 2016 $ (2,497,231 )
Other comprehensive income 192,809
Balance at June 30, 2017 $ (2,304,422 )



	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2017	$	(1,202,264	)
Other comprehensive income	40,396
Balance at December 31, 2017	$	(1,161,868	)


8.	Commitments and Contingencies

On June 28, 2017, the Company announced that effective July 21, 2017, all customer support services functions would be outsourced resulting in a reduction of 18 employees. The Company recorded approximately $135,000 in severance-related expenses for the impacted employees.

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 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.


9.	Earnings Per Share

Basic earnings per common share for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2017 and 2016 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,
2017 2016 2017 2016
Net Income $ 615,562
$ 627,068
$ 6,072,979
$ 5,661,305
Weighted average common shares 7,227,171
7,160,650
7,212,289
7,140,914
Effect of dilutive securities:
Options to purchase common stock 46,669
12,062
32,275
7,951
Diluted average common shares 7,273,840
7,172,712
7,244,564
7,148,865
Earnings Per Share of Common Stock:
Basic $ 0.09
$ 0.09
$ 0.84
$ 0.79
Diluted $ 0.08
$ 0.09
$ 0.84
$ 0.79



	Three Months Ended December 31,
	2017		2016
Net Income	$	2,059,462	$	2,232,218
Weighted average common shares	7,248,094		7,194,594
Effect of dilutive securities:
Options to purchase common stock	48,086		15,953
Diluted average common shares	7,296,180		7,210,547
Earnings Per Share of Common Stock:
Basic	$	0.28	$	0.31
Diluted	$	0.28	$	0.31


10.	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,
2017 2016 2017 2016
Components of net periodic pension cost:
Service cost $ 176,669
$ 173,594
$ 530,007
$ 520,782
Interest cost 248,900
283,194
746,700
849,582
Expected return on plan assets (404,103 ) (373,060 ) (1,212,309 ) (1,119,180 )
Recognized loss 165,545
125,420
496,635
376,260
Net periodic pension cost $ 187,011
$ 209,148
$ 561,033
$ 627,444

RGC RESOURCES, INC. AND SUBSIDIARIES

Three Months Ended Nine Months Ended
June 30, June 30,
2017 2016 2017 2016
Components of postretirement benefit cost:
Service cost $ 45,817
$ 37,005
$ 137,451
$ 111,015
Interest cost 156,706
156,145
470,118
468,435
Expected return on plan assets (142,878 ) (126,965 ) (428,634 ) (380,895 )
Recognized loss 107,440
62,543
322,320
187,629
Net postretirement benefit cost $ 167,085
$ 128,728
$ 501,255
$ 386,184



	Three Months Ended
	December 31,
	2017			2016
Components of net periodic pension cost:
Service cost	$	166,309		$	176,669
Interest cost	272,045			248,900
Expected return on plan assets	(465,710		)	(404,103		)
Recognized loss	87,758			165,545
Net periodic pension cost	$	60,402		$	187,011



	Three Months Ended
	December 31,
	2017			2016
Components of postretirement benefit cost:
Service cost	$	41,805		$	45,817
Interest cost	160,151			156,706
Expected return on plan assets	(155,845		)	(142,878		)
Recognized loss	70,967			107,440
Net postretirement benefit cost	$	117,078		$	167,085

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

Fiscal Year-to-Date Contributions Remaining Fiscal Year Contributions
Defined benefit pension plan $ 450,000
$ 300,000
Postretirement medical plan —
1,000,000
Total $ 450,000
$ 1,300,000



	Fiscal Year-to-Date Contributions		Remaining Fiscal Year Contributions
Defined benefit pension plan	$	400,000	$	1,200,000
Postretirement medical plan	150,000		450,000
Total	$	550,000	$	1,650,000


11.	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 ~~broad~~ levels:

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

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

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

RGC RESOURCES, INC. AND SUBSIDIARIES

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,~~December 31, 2017 and September 30, ~~2016:~~2017:

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~


			Fair Value Measurements - June 30, 2017								Fair Value Measurements - December 31, 2017
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	118,606	$	—	$	118,606	$	—	$	179,582	$	—	$	179,582	$	—
Total	$	118,606	$	—	$	118,606	$	—	$	179,582	$	—	$	179,582	$	—

Liabilities:
Natural gas purchases	$	1,880,645	$	—	$	1,880,645	$	—	$	1,148,415	$	—	$	1,148,415	$	—
Total	$	1,880,645	$	—	$	1,880,645	$	—	$	1,148,415	$	—	$	1,148,415	$	—

			Fair Value Measurements - September 30, 2016								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)		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	$	1,052,930	$	—	$	1,052,930	$	—	$	805,159	$	—	$	805,159	$	—
Total	$	1,052,930	$	—	$	1,052,930	$	—	$	805,159	$	—	$	805,159	$	—

The fair value of the interest rate swap ~~included in the line item "Fair value of marked-to-market transactions",~~ 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,~~December 31, 2017 and September 30, ~~2016,~~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,~~December 31, 2017 and September 30, ~~2016:~~2017:

RGC RESOURCES, INC. AND SUBSIDIARIES


			Fair Value Measurements - June 30, 2017								Fair Value Measurements - December 31, 2017
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt - notes payable	$	42,820,200	$	—	$	—	$	44,295,661
Long-term debt									$	53,076,200	$	—	$	—	$	54,759,595
Total	$	42,820,200	$	—	$	—	$	44,295,661	$	53,076,200	$	—	$	—	$	54,759,595

			Fair Value Measurements - September 30, 2016								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)		Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt - notes payable	$	33,896,200	$	—	$	—	$	36,163,523
Long-term debt									$	43,812,200	$	—	$	—	$	45,689,238
Total	$	33,896,200	$	—	$	—	$	36,163,523	$	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,~~December 31, 2017 and September 30, ~~2016,~~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.


12.	~~Stock Options~~

On December 8, 2016, the Board of Directors granted 25,500 options to certain officers of the Company. In accordance with the Key Employee Stock Option Plan, the grant price of $16.37 was the closing price of the Company's stock on the grant date. The options become exercisable six months from the grant date and expire after ten years from the date of issuance.

Fair value at the grant date was $2.89 per option as calculated using the Black-Scholes option pricing model. Compensation expense is recognized over the vesting period. Total compensation expense recognized through ~~June 30, 2017~~ ~~was~~ ~~$73,780. The number of options granted, grant price and option value have been adjusted for the stock split effective March 1, 2017.~~


~~13.~~	Subsequent Events

The Company has evaluated subsequent events through the date the financial statements were issued. There were no items not otherwise disclosed 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 ~~2016~~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, ~~2017.~~2018. The total revenues and margins realized during the first ~~nine~~three months reflect higher billings due to the weather sensitive nature of the gas business.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately ~~60,000~~61,200 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

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

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

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

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.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

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

The WNA model reduces earnings volatility, related to weather variability in the heating season, by providing the Company a level of earnings protection when weather is warmer than normal and providing customers price protection when the weather is colder than normal. The WNA is based on a weather measurement band around the most recent 30-year temperature average. Under the WNA, the Company recovers from its customers the lost margin (excluding gas costs) for the impact of weather that is warmer than normal or refunds the excess margin earned for weather that is colder than normal. The WNA mechanism used by the Company is based on a linear regression model that determines the value of a single heating degree day. For the three months ended ~~June 30,~~December 31, 2017 and 2016, the Company accrued approximately ~~$255,000~~$37,000 and ~~$42,000~~$623,000 in additional revenue and margin for weather that was 1% and 15% warmer than normal, ~~during each of the periods,~~ respectively. For the nine months ended June 30, 2017 and 2016, the Company accrued approximately $1,860,000 and $1,223,000 in additional revenue and margin for weather that had nearly 19% and 12% fewer heating degree days 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~~three months of the current fiscal year was ~~$0.21~~$0.31 per decatherm, or 7%11%, ~~lower~~higher than the same period last year, as ~~the Company benefited from lower~~ natural gas commodity prices were higher during the ~~summer~~ storage ~~refill period~~replenishment in ~~calendar~~2017 as compared to 2016. With the beginning of the current year summer storage refill in April, natural gas prices purchased for the storage delivery were higher than for the same period last year, which combined with higher average volumes of gas in storage has increased the average total cost of natural gas in storage during the quarter by nearly 18%. However, the ratio of debt to equity has increased from last year, leading to a reduction in the ICC factor applied to inventory balances. The net result is a ~~smaller~~small increase in ICC revenues for the quarter compared to last year and a decrease for the nine-month period. Natural gas futures are currently higher than the average price of gas in storage, which may result in higher average cost and ICC revenues as storage balances are replenished during the summer months.quarter.

The Company’s non-gas rates provide for the recovery of non-gas related expenses and a reasonable return to shareholders. These rates are determined based on the filing of a formal rate application with the SCC utilizing historical information, including investment in natural gas facilities. Generally, investments related to extending service to new customers are recovered through the non-gas rates currently in place. The investment in replacing and upgrading existing infrastructure is not recoverable until a formal rate application is filed and approved to include the additional investment in new non-gas rates. The SAVE Plan, however, provides the Company with the ability to recover costs related to investments in qualified infrastructure projects on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism through which the Company may recover the related depreciation and expenses and provide a return on rate base for the additional capital investments related to improving the Company's infrastructure until such time that a formal rate application is filed to incorporate this investment in the Company's non-gas rates. As the Company did not file for an increase in ~~the~~ non-gas rates during the prior ~~three~~four years and the level of capital investment continues to grow, SAVE Plan revenues have continued to ~~increase.~~increase corresponding to the growth in qualified SAVE related infrastructure projects. The Company ~~recognized~~recorded approximately ~~$965,000 and $2,768,000~~

RGC RESOURCES, INC. AND SUBSIDIARIES

$1,076,000 in SAVE Plan revenues for the three-month ~~and nine-month periods~~period ended ~~June 30,~~December 31, 2017 compared to ~~$664,000 and $1,701,000~~$881,000 for the same ~~periods~~period last year. These SAVE Plan revenues will be included as part of the new non-gas base rates the next time the Company files for a non-gas rate increase.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

Results of Operations

Three Months Ended ~~June 30,~~December 31, 2017:

Net income declined by ~~$11,506~~$172,756 for the three months ended ~~June 30,~~December 31, 2017, compared to the same period last year. ~~Increases~~The adjustment to deferred income taxes on the Company's unregulated operations, related to the reduction in ~~SAVE Plan revenues nearly~~the federal corporate income tax rate, accounted for most of the reduction in net income. The impact on the regulated operations of Roanoke Gas was limited as the excess deferred tax adjustment was transferred to a regulatory liability and the reduction in current tax expense was offset by a reduction in ~~capitalized overheads and severance costs related to the outsourcing of the customer support services function.~~revenue.

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


	Three Months Ended June 30,									Three Months Ended December 31,
	2017		2016		Increase / (Decrease)			Percentage		2017		2016		Increase / (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	11,171,499	$	11,017,281	$	154,218		1	%	$	18,519,994	$	18,512,333	$	7,661		—	%
Other	264,325		277,916		(13,591		)	(5	)%	236,057		276,252		(40,195		)	(15	)%
Total Operating Revenues	$	11,435,824	$	11,295,197	$	140,627		1	%	$	18,756,051	$	18,788,585	$	(32,534	)	—	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	769,795		865,471		(95,676		)	(11	)%	2,216,709		1,941,497		275,212			14	%
Transportation and Interruptible	631,297		658,869		(27,572		)	(4	)%	737,108		692,998		44,110			6	%
Total Delivered Volumes	1,401,092		1,524,340		(123,248		)	(8	)%	2,953,817		2,634,495		319,322			12	%
Heating Degree Days (Unofficial)	245		332		(87		)	(26	)%	1,497		1,287		210			16	%

Total operating revenues for the three months ended ~~June 30,~~December 31, 2017, compared to the same period last year, decreased slightly as lower average commodity prices during the first quarter of fiscal 2018 combined with the excess revenue adjustment offset the effect of higher delivered volumes and SAVE revenues. The average commodity price of natural gas delivered during the current quarter was approximately 8% per decatherm less than the same period last year. The Company also recorded a reserve in the amount of $462,442 associated with the estimated excess revenues billed to customers as a result of the reduction in the corporate income tax rate. Total natural gas deliveries increased ~~primarily~~by 12% over last year due to ~~higher SAVE Plan revenues and natural gas commodity prices, partially offset~~the colder weather as evidenced by ~~lower customer volume deliveries.~~the 16% increase in total heating degree days. As discussed in more detail above, SAVE Plan revenues continue to grow as the Company continues to invest in its SAVE related infrastructure replacement program, allowing for recovery of the cost and a return on investment in the new facilities. In addition, the commodity price of natural gas increased by more than 10% per decatherm over the same period last year. The Company is able to recover the higher commodity price through its PGA factor. Due to the warmer weather during the quarter, primarily in April, weather sensitive residential and commercial sales volumes declined by 11% with total natural gas deliveries declining by 8%. The Company was able to recover most of the lost margin attributable to warmer weather through the WNA mechanism. Transportation and industrial volumes declined by 4% due in part to warmer weather.


	Three Months Ended June 30,								Three Months Ended December 31,
	2017		2016		Increase		Percentage		2017		2016		Decrease			Percentage
Gross Margin
Gas Utilities	$	6,492,452	$	6,183,677	$	308,775	5	%	$	8,958,588	$	9,265,481	$	(306,893	)	(3	)%
Other	141,950		128,663		13,287		10	%	114,847		125,424		(10,577		)	(8	)%
Total Gross Margin	$	6,634,402	$	6,312,340	$	322,062	5	%	$	9,073,435	$	9,390,905	$	(317,470	)	(3	)%

Regulated natural gas margins from utility operations ~~increased~~decreased from the same period last year primarily as a result of ~~higher SAVE Plan revenues. SAVE~~the reduction in regulated revenues ~~increased by $300,209~~of Roanoke Gas due to the ~~continuing investment~~estimated excess revenues reserve discussed in more detail above and under the Tax Reform and Regulatory section below. An increase in SAVE ~~related projects. Total volumetric margin, net~~revenues of the WNA adjustment, decreased slightly by $11,660, or less than 1.0%, due to reductions in transportation and interruptible deliveries. The residential and commercial volumes as adjusted for WNA reflected an increase of more than 1% in volumes. The remaining margin increase was attributable to$195,824, along with increases in customer base charge, ~~from customer growth, higher ICC revenues due to higher average inventory balances for the quarter~~carrying cost and other gas ~~revenues. Other margins reflected~~revenues, offset a ~~small increase over last year.~~net reduction in WNA adjusted volumetric margins.

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

RGC RESOURCES, INC. AND SUBSIDIARIES


	Three Months Ended June 30,							Three Months Ended December 31,
	2017		2016		Increase / (Decrease)			2017			2016		Increase / (Decrease)
Customer Base Charge	$	3,112,654	$	3,104,082	$	8,572		$	3,102,106		$	3,083,808	$	18,298
Carrying Cost	107,051		100,179		6,872			204,279			197,801		6,478
SAVE Plan	964,697		664,488		300,209			1,076,419			880,595		195,824
Volumetric	2,025,593		2,250,298		(224,705		)	4,960,473			4,451,642		508,831
WNA	255,163		42,118		213,045			36,770			622,959		(586,189		)
Other Gas Revenues	27,294		22,512		4,782			40,983			28,676		12,307
Excess Revenue Refund								(462,442		)	—		(462,442		)
Total	$	6,492,452	$	6,183,677	$	308,775		$	8,958,588		$	9,265,481	$	(306,893	)

Operation and maintenance expenses ~~increased by $234,504,~~decreased $194,717, or 8%6%, from the same period last ~~year. Severance costs~~year primarily related to reductions in benefit costs. Total employee benefit costs declined by $238,000. The benefit cost reduction includes a $177,000 decrease in the ~~outsourcing~~actuarially determined expenses, due to strong asset performance of both the the pension and the other post-retirement benefit plans, higher discount rate for valuing the benefit plan liabilities and a soft freeze of the pension plan. The remaining reduction in benefit costs is attributable to fewer total employees resulting from outsourcing customer support services ~~functions, lower capitalized overheads and increases~~in fiscal 2017. The net reduction in employee benefit costs ~~more than~~combined with lower payroll were partially offset ~~reductions in corporate property and liability insurance premiums and other costs. The Company accrued $135,000 in severance related payroll and benefit costs for the 18 employees who were displaced~~by higher contracted services, primarily due to ~~the changes in the~~ customer service area. These costs will be paid in the next quarter. Total capital expenditures subject to general and administrative overheads declined by nearly 5% for the quarter. This reduction in eligible expenditures combined with a lower overhead factor resulted in $120,000 less overhead capitalization. The reduction in capital expenditures was due to the level and timing expenditures between the quarters. Total capital expenditures for the year remain well above last year's levels. Employee benefit costs increased by $73,000 due to increased health insurance premiums and higher actuarial determined retirement plan costs. The Company continues to benefit from the reduction in corporate property and liability insurance cost due to favorable policy renewals. Premium expense declined by $46,000 for the quarter. The remaining differences were related to various minor fluctuations in other expenses.outsourcing.

General taxes increased by ~~$36,817,~~$25,248, or 9%6%, due to higher property taxes associated with increases in utility ~~property.~~property partially offset by lower payroll taxes associated with fewer employees.

Depreciation expense increased by ~~$175,884,~~$159,150, or ~~13%~~10%, on a corresponding increase in utility plant investment.

Equity in earnings of unconsolidated affiliate increased by ~~$71,064,~~$64,271, or ~~175%~~76%, due to the increasing investment in the Mountain Valley Pipeline ("MVP") project. ~~This project began in the first quarter of fiscal 2016 and the~~The corresponding earnings are primarily composed of allowance for funds used during construction ("AFUDC"). The equity in earnings amount will continue to increase as the investment in the MVP project continues. Additional information about the Company's investment in the MVP can be found under the Equity Investment in Mountain Valley Pipeline section below.

Other expense, net ~~decreased~~increased by ~~$30,413~~$12,420 primarily due to ~~lower~~higher pipeline assessments.

Interest expense increased by ~~$75,996,~~$154,124, or ~~19%~~34%, due to ~~increased borrowing~~a 27% increase in total average debt to finance the Company's capital budget and the Company's investment in ~~MVP. Total average debt outstanding during~~MVP and rising interest rates on the ~~quarter increased by 31% over~~Company's variable rate debt. The combination of the ~~same period last year, while~~issuance of the new $8,000,000 notes and rising interest rates on the line-of-credit and Midstream notes served to increase the weighted-average effective interest rate ~~declined~~ from ~~4.05%~~3.41% in the first quarter of fiscal 2017 to ~~3.69% due to~~3.60% during the ~~additional borrowing on lower interest rate debt.~~first fiscal quarter of 2018.

Income tax expense declined by ~~$88,156,~~$236,668, or ~~20%~~17%. The reduction in income taxes was a product of lower pre-tax income and the application of lower income tax rates due to the passage of the Tax Act. The combined state and federal tax rate declined from 37.96% to a blended 28.84% in fiscal 2018. The effective tax rate was ~~36% and 41%~~35.5% for the ~~three months ended June 30, 2017 and 2016, respectively. The difference in the effective tax rate was due~~quarter compared to the exercise of stock options during the quarter, which resulted in additional tax deductions above the amount recorded at grant due to the significant appreciation in stock price. During the prior year, the effective tax rate was higher than the statutory rate due to higher non-deductible expenses and the expiration of unexercised stock options.

~~Nine Months Ended June 30, 2017:~~

~~Net income increased by $411,674~~38.1% for ~~the nine months ended June 30, 2017, compared to~~ the same period last year. ~~Increases in SAVE Plan revenues, earnings from the investment in the MVP project and higher capitalized overheads were the primary reasons for the growth in net income.~~

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

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

Nine Months Ended
June 30,
2017 2016 Increase / (Decrease) Percentage
Operating Revenues
Gas Utilities $ 51,346,456
$ 48,372,615
$ 2,973,841
6 %
Other 777,966
710,411
67,555
10 %
Total Operating Revenues $ 52,124,422
$ 49,083,026
$ 3,041,396
6 %
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial 5,305,263
5,567,255
(261,992 ) (5 )%
Transportation and Interruptible 2,115,333
2,158,032
(42,699 ) (2 )%
Total Delivered Volumes 7,420,596
7,725,287
(304,691 ) (4 )%
Heating Degree Days (Unofficial) 3,213
3,484
(271 ) (8 )%

Total operating revenues for the nine months ended June 30, 2017, compared to the same period last year, increased due to the increase in SAVE Plan revenues and higher natural gas commodity prices partially offset by lower delivered volumes. SAVE Plan revenues increased by $1,066,320 as investments in SAVE related projects continued. The commodity price for natural gas increased by 17% per decatherm. As the cost of natural gas is a pass-through to the Company's customers, revenues were increased through the PGA factor to recover the corresponding higher costs. Total natural gas deliveries decreased by 4% due to warmer weather, as evidenced by the 8% reduction in heating degree days. Residential and commercial volumes decreased by 5% due to warmer weather, while transportation and industrial volumes decreased slightly from the same period last year.

Nine Months Ended
June 30,
2017 2016 Increase Percentage
Gross Margin
Gas Utilities $ 26,484,309
$ 25,334,719
$ 1,149,590
5 %
Other 370,728
365,006
5,722
2 %
Total Gross Margin $ 26,855,037
$ 25,699,725
$ 1,155,312
4 %

Utility margins increased from the same period last year primarily as a result of higher SAVE Plan revenues and customer growth. SAVE revenues increased by $1,066,320 due to the increasing investment in SAVE related projects. Volumetric margin, net of the WNA adjustment, increased by $99,072 as a result of a 1% increase in WNA adjusted volumes. The increase in net volumetric margin and customer base charges are attributable to customer growth, while lower average gas storage balances during the nine month period reduced carrying cost revenues. Other margins experienced a small increase on higher revenues.

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

Nine Months Ended
June 30,
2017 2016 Increase / (Decrease)
Customer Base Charge $ 9,330,860
$ 9,288,474
$ 42,386
Carrying Cost 406,838
464,883
(58,045 )
SAVE Plan 2,767,636
1,701,316
1,066,320
Volumetric 12,033,663
12,571,627
(537,964 )
WNA 1,860,497
1,223,461
637,036
Other Gas Revenues 84,815
84,958
(143 )
Total $ 26,484,309
$ 25,334,719
$ 1,149,590

Operation and maintenance expenses were nearly unchanged from the same period last year with an increase of $12,129. Increased capitalized overheads and lower corporate property and liability insurance premiums offset severance costs and higher employee benefit expenses. Although capitalized expenses were down for the quarter, expenditures subject to the

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

overheads increased by 35% for the nine-month period. As a result, capitalized construction overheads increased by more than $193,000. The combination of the ongoing pipeline renewal program and the automated meter reading system project accounted for the increased capital spending during the year. Corporate property and liability insurance premiums declined by $148,000 due to improvements in the insurance market. These expense reductions were offset by $134,000 in accrued payroll and benefit costs associated with the severance package offered to employees impacted by the outsourcing of the customer service function and $188,000 in higher employee benefit costs related to increased health insurance premiums and higher actuarial determined retirement plan costs. The remaining differences were related to various minor fluctuations in other expenses.

~~General taxes increased by $91,558, or 7%, due to higher property taxes associated with increases in utility property.~~

~~Depreciation expense increased by $547,652, or 13%, on higher utility plant investment.~~

~~Equity in earnings of unconsolidated affiliate increased by $193,846, or 202%, as the investment in the MVP project continues to grow.~~

~~Other expense, net decreased by $48,440 primarily due to lower pipeline assessments and timing of charitable giving.~~

Interest expense increased by $179,701, or 15%, due to the Company's increased borrowing to finance its capital investment in infrastructure and the MVP. Total average debt outstanding during the current period increased by 17% over the same period last year, while the weighted average effective interest rate declined slightly from 3.76% to 3.71%.

~~Income tax expense increased by $154,884, or 4%, which corresponds to an increase in pre-tax income for the period.~~ The effective tax rate for the current quarter is higher than the blended rate of 28.84% due to the valuation adjustments to the net deferred tax assets of the unregulated operations. These valuation adjustments to deferred taxes of the unregulated operations are charged to income tax expense in accordance with U.S. GAAP. Since the unregulated operations had a net deferred tax asset, the adjustment resulted in a charge to income tax expense of approximately $208,000. Excluding the $208,000 tax adjustment, the effective tax rate for the current quarter would have been 29%. The valuation adjustment to the net deferred tax liability of the regulated operations of Roanoke Gas was ~~38% for both periods.~~transferred to a regulatory liability as discussed in Note 3. Additional information regarding the Tax Act and its impact on the Company is provided under the Regulatory and Tax Reform sections below.

Critical Accounting Policies and Estimates

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

RGC RESOURCES, INC. AND SUBSIDIARIES

The Company considers an estimate to be critical if it is material to the financial statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company's current quarter adjustments for the effect of the Tax Act includes estimates related to the revaluation of deferred income tax adjustments due to the blended income tax rate and the refund of excess billings to customers pending revisions to customer billing rates to be approved by the SCC. The Company believes these adjustments to be reasonable estimates of the financial effect of the tax change based on the best information available. These estimates will be adjusted as necessary once the SCC reviews and approves the Company's calculations and methodology. There have been no other changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, ~~2016.~~2017.

Asset Management

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

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company through its wholly-owned subsidiary, RGC Midstream, LLC ("Midstream"), entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the "LLC"). The purpose of the LLC is to construct and operate the MVP, a natural gas pipeline connecting ~~an existing~~Equitran's gathering and transmission system in northern West Virginia to ~~another~~the Transco interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. InOn October 2015, the LLC filed the application with FERC to construct the pipeline. On June 28, 2016, FERC issued the Notice of Schedule for Environmental Review ("NOS"); on September 16, 2016, FERC issued its draft environmental impact statement ("EIS") regarding the MVP; and on June 23,13, 2017, FERC issued the ~~Final EIS for~~MVP Certificate of Public Convenience and Necessity, and in January 2018, FERC issued the ~~MVP. The Final EIS noted that "... approval of the projects would result in some adverse environmental impacts, but the majority of these impacts would be reduced~~first Notice to ~~less-than-significant levels." The MVP project will now be sent to the FERC Commissioners for approval. Upon receiving FERC approval,~~Proceed ("NTP"), which granted the LLC ~~will commence~~permission to begin construction on 93 access roads and 6 construction staging areas at defined locations in West Virginia as a precursor to construction of the pipeline and ~~is targeting an~~a second NTP approving the construction of compressor stations and interconnects in West Virginia . The LLC has submitted additional requests to FERC for NTP, which are pending approval at this time. The LLC has received the necessary federal permits and the required Virginia and West Virginia environmental agency permits. The managing partner of the LLC currently anticipates the in-service date byfor the MVP to be the end of calendar 2018.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

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 ~~impact~~risk from such an event. In addition, the proposed pipeline path would provide the Company with a more economically feasible opportunity to provide natural gas service to previously unserved areas in southwest Virginia.

The total project cost is anticipated to be approximately $3.5 billion. As a 1% member in the LLC, Midstream's cash contribution is expected to be approximately $35 million. The agreement provides for a schedule of cash draws to fund the project. The initial payments ~~are~~were for the acquisition of land and materials related to the construction of the pipeline and other pre-construction costs. ~~Once approved~~As the Notices to Proceed are granted, construction activities will escalate and ~~construction begins,~~ more significant cash draws will be required. Initial funding for the investment in the LLC is provided through the Midstream credit facility under which Midstream may borrow up to a total of $25 million ~~over a period of 5 years,~~through 2020 with the balance coming from ~~equity capital. The Company expects to fund the~~a combination of equity capital ~~portion from the issuance of additional common stock. The number of shares issued~~ and ~~the amount raised will be determined after an assessment of the overall capital needs of the Company and will depend on capital market conditions.~~

debt.

A majority of the earnings from the investment in MVP ~~relates~~relate to AFUDC income generated by the deployment of capital in the design, engineering, materials procurement, project management and ultimately construction of the pipeline. AFUDC is an accounting method whereby the costs of debt and equity funds used to finance facility infrastructure are credited to income and charged to the cost of the project. The level of investment in the MVP will continue to grow at a steady pace until such time FERC issues their decision on the project. ~~If approved,~~As the NTPs are received, construction on the pipeline ~~should~~will begin in earnest and both the investment in the MVP and the AFUDC will increase at a much greater rate until the pipeline is placed in service. Earnings after the pipeline becomes operational would be derived from the fees charged for transporting natural gas through the pipeline.

RGC RESOURCES, INC. AND SUBSIDIARIES

Tax Reform and Regulatory

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

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

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 adjustment to income tax expense. The Company reclassified the revaluation adjustments associated with Roanoke Gas' deferred income taxes to a regulatory liability. This liability was grossed up for the effective tax rate as amounts will be refunded to customers through an adjustment to billed revenues.

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



	Change in Net Deferred Tax Liability		Income Tax Expense		Regulatory Liability
Revaluation of deferred income taxes	8,748,114		(44,524	)	(8,703,590	)
Revaluation of deferred income taxes in OCI - defined benefit plans	(252,812	)	252,812		—
Revaluation of deferred income taxes in OCI - interest rate swap	16,223		—		(16,223	)
Gross up of regulatory liability	3,022,461		—		(3,022,461	)
Net Change	11,533,986		208,288		(11,742,274	)

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

RGC RESOURCES, INC. AND SUBSIDIARIES

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On ~~June 30,~~September 28, 2017, the Company ~~filed its 2018~~received SCC approval to implement new SAVE ~~Plan application with~~rates related to the ~~SCC. The original~~proposed qualifying SAVE ~~Plan was approved by the SCC through an order issued on August 29, 2012 and has been modified amended or updated each year since. The original~~investments in calendar 2018. These new SAVE ~~Plan was~~rates are designed ~~to facilitate the accelerated replacement of the remaining bare steel and cast iron natural gas pipe by providing a mechanism for the Company~~ to recover the ~~related depreciation and~~additional expenses ~~and return on rate base~~ of the ~~additional capital~~SAVE investment without the filing of a formal application for an increase in non-gas base rates. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. The amendments in 2013 and 2014 added projects related to the replacement of bare steel and cast iron natural gas pipe in addition to ~~two other major projects and~~a return on the investment for related meter and regulator installations located on customer premises. In 2015, the SCC approved the Company's request to expand the authorized annual spending variance from 10% to 20% and set a 5% cumulative SAVE spending variance. This allows the Company to recover its investment up to the new variance limits. The 2016 and 2017 applications included provisions to continue the ongoing pipeline renewal project with a focus on pre-1973 plastic pipe, replacement of natural gas custody transfer stations and the replacement of coated steel tubing services and related meter installations. In the 2018 SAVE Plan application, the revenue requirement is approximately $5,000,000, representing an increase ~~of almost $1,000,000 over the estimated 2017 SAVE Plan year.~~in rate base. The 2018 SAVE Plan continues ~~the~~to focus on the replacement of the pre-1973 plastic pipe and includes the replacement ofon one custody transfer station. The Company anticipates the SCC will complete its review of the application over the next few months and will implement the approved rates beginning in January 2018. If approved, the additional SAVE Plan revenue generated by the SAVE Plan rider will allow the Company to forgo a formal non-gas rate increase application at this time.

The Company's WNA year runs from April through March. At the end of the WNA year ended March 31, 2017, the Company had more than $1.7 million in WNA revenues accrued for weather that was nearly 18% warmer than the 30-year normal. In April, the Company submitted to the SCC its proposed WNA billing factors designed to recover the revenue shortfall attributable to the warmer weather. The SCC approved the billing factors to be used for a three-month period. Beginning in May 2017, the Company began billing customers for the WNA revenue. As of June 30, 2017, $572,000 of WNA was in the accounts receivable balance to be billed to customers in the July billing cycle.

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

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 ~~capital raised through the Company’s stock plans.~~equity capital.

Cash and cash equivalents increased by ~~$120,564~~$264,638 for the ~~nine-month~~three-month period ended ~~June 30,~~December 31, 2017, compared to a ~~$80,401~~$467,177 decrease for the same period last year. The following table summarizes the sources and uses of cash:

Nine Months Ended
June 30,
2017 2016
Cash Flow Summary Nine Months Ended
Net cash provided by operating activities $ 15,751,066
$ 15,535,449
Net cash used in investing activities (18,240,994 ) (14,830,542 )
Net cash provided by (used in) financing activities 2,610,492
(785,308 )
Increase (decrease) in cash and cash equivalents $ 120,564
$ (80,401 )



	Three Months Ended December 31,
	2017			2016
Cash Flow Summary Three Months Ended
Net cash used in operating activities	$	(1,958,693	)	$	(2,112,988	)
Net cash used in investing activities	(5,539,387		)	(4,922,829		)
Net cash provided by financing activities	7,762,718			6,568,640
Increase (decrease) in cash and cash equivalents	$	264,638		$	(467,177	)

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

Cash flow provided by operations is primarily driven by net income, depreciation and reductions in natural gas storage inventory during the first ~~nine~~three months of the fiscal year. Cash flow ~~provided by operations~~from operating activities increased from the same period last year by ~~$215,617,~~$154,295, primarily due to a greater increase in ~~net income, depreciation~~over-collections on gas cost and ~~over-collection of gas costs. The~~a smaller increase in ~~cash provided~~accounts receivable offset by ~~over-collection of~~a much smaller decrease in gas ~~costs~~in storage. The smaller increase in accounts receivable is attributable to ~~actual gas cost increases being less than~~ the ~~projected costs~~large WNA accrual included in ~~the PGA billing rate. Any over-collection remaining at the end of~~accounts receivable last year compared to the current ~~PGA period will be refunded to customers next year. Much~~quarter. The first quarter of last year was 15% warmer than normal which generated a WNA receivable of $622,959, while the ~~increase~~current quarter was nearly normal with a WNA accrual of only $36,770. Removing the WNA accruals would have resulted in cash provided by net income, depreciation and over-collection of gas costs was offset by a decline in cash generated from reductions in gas storage. Higher natural gas commodity prices for deliveries of gas into storage during the current year ~~combined with higher~~having a bigger increase in accounts receivable. The smaller decrease in gas in storage ~~levels~~is due to ~~a warmer winter heating season resulted in a much smaller reduction in~~the beginning storage ~~gas~~ levels for the ~~period.~~current quarter being below the same period last year resulting in additional gas delivered to storage in October and November 2017 to bring storage levels comparable to last year. A summary of the cash provided by operations is listed below:


	Nine Months Ended June 30,									Three Months Ended December 31,
Cash Flow From Operating Activities:	2017			2016			Increase / (Decrease)			2017			2016			Increase / (Decrease)
Net income	$	6,072,979		$	5,661,305		$	411,674		$	2,059,462		$	2,232,218		$	(172,756	)
Depreciation	4,793,270			4,245,223			548,047			1,765,779			1,606,090			159,689
Increase in over-collections	2,348,534			767,194			1,581,340			678,376			241,548			436,828
Decrease in gas in storage	1,991,510			3,856,242			(1,864,732		)	795,238			1,616,516			(821,278		)
Increase in accounts receivable	(1,385,998		)	(1,077,678		)	(308,320		)	(7,503,973		)	(8,000,539		)	496,566
Increase (decrease) in accounts payable	277,786			(68,557		)	346,343
Increase in accounts payable										1,058,639			927,340			131,299
Other	1,652,985			2,151,720			(498,735		)	(812,214		)	(736,161		)	(76,053		)
Net Cash Provided by Operations	$	15,751,066		$	15,535,449		$	215,617
Net Cash Used in Operations										$	(1,958,693	)	$	(2,112,988	)	$	154,295

RGC RESOURCES, INC. AND SUBSIDIARIES

Investing activities are generally composed of expenditures related to investment in the Company's utility plant projects, which includes replacing aging natural gas pipe with new plastic or coated steel pipe, improvements to the LNG plant and distribution system facilities, expanding its natural gas system to meet the demands of customer growth, as well as the continued investment in the MVP. The Company ~~completed the replacement of~~is continuing its ~~bare steel and cast iron pipe during the first quarter and is now focused~~focus on ~~continued~~ SAVE infrastructure replacement projects including the replacement of ~~approximately 45 miles of~~ pre-1973 first generation plastic pipe and ~~upgrades to three~~replacement of a natural gas transfer ~~stations.~~station. Total capital expenditures for ~~additions to property during~~ the ~~first nine months of the year~~quarter were ~~$16.5~~$4.3 million, which represented a ~~$3.9 million increase~~

~~RGC RESOURCES, INC. AND SUBSIDIARIES~~

~~over~~$132,000 reduction from the same period last year. The ~~increase~~small decrease is attributable in part to expenditures made last year related to the ~~Company's expenditures for installing~~installation of an automated meter reading system ("AMR")~~. The AMR project, which involves the retrofitting of all customer meters with transmitters to allow consumption data to be collected remotely, is projected to be~~ completed ~~by the end of~~in fiscal 2017. Although the current fiscal ~~year. The~~year capital budget does not include the AMR project, it does ~~not qualify~~include increased activity on SAVE Plan projects as ~~a SAVE project subject~~well as proposed system reinforcements and the installation of two interconnects to ~~immediate recovery of~~MVP with the related investment costs and expenses; however, the Company expects future cost savings through reduced meter reading and billing costs. The combination of the AMR and SAVE related projects have resulted in a projected fiscal 2017Company's distribution system. Total capital ~~budget of more than $20 million. Operating cash flows and additional corporate borrowings~~expenditures are expected to ~~provide the majority of the funding~~exceed $20 million for ~~these projects.~~fiscal 2018.

Investing cash flows also ~~reflect~~includes the Company's ~~continued~~ funding of its participation in the MVP, with a total cash investment of ~~$1,803,100~~$1,232,980 for the ~~nine~~three months ended ~~June 30,~~December 31, 2017. The ~~level of~~planned investment in the MVP is expected to accelerate significantly as FERC has ~~moderated pending FERC approval If approved by FERC,~~issued two NTPs allowing for construction activity to begin in West Virginia. With construction slated to begin immediately and the remaining NTPs expected shortly, the Company ~~expects to invest~~anticipates an ~~estimated total~~increase in its utilization of ~~$35 million in the project. Initial funding for the investment in the LLC is provided through~~ the Midstream credit ~~facility, as discussed above and in Note 6 of the Condensed Consolidated Financial Statements.~~facility. The Company also expects that the remaining funding for MVP to be provided by a ~~portion~~combination of ~~the funding will come from the issuance of its common stock.~~equity capital and additional debt. Management is currently evaluating the capital needs and timing related to ~~the~~its investment in MVP as well as the funding requirements for the Company's ongoing pipeline renewal and infrastructure improvements. Based on the results of this assessment and capital market conditions, the Company plans to determine the level ~~and timing~~ of ~~any~~ equity ~~financing.~~capital needed with an anticipated common stock offering sometime later this year.

Financing activities generally consist of long-term and line-of-credit borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flows provided by financing activities were ~~$2,610,492~~$7,762,718 for the current period compared to ~~a use of $785,308~~$6,568,640 for the same period last year. The ~~$3.3 million swing~~increase in financing cash flows is attributable to ~~the additional borrowing required~~higher borrowings to ~~support~~finance the increased ~~capital expenditures noted above.~~investment in MVP. The ~~primary difference~~Company borrowed $1,264,000 under the Midstream credit facility during the current quarter compared to $508,000 for the same period last year. In addition, Roanoke Gas issued $8,000,000 in ~~financing activities between~~notes in October 2017 compared to a $7,000,000 bank note issued during the ~~two periods relates to the issuance of a 5-year unsecured note in the principal amount of $7,000,000 on November 1, 2016. The proceeds from this note~~prior year. These notes were used to ~~convert a portion~~refinance part of the line-of-credit balance ~~supporting Roanoke Gas'~~that provided capital expenditures into a longer-term financing instrument. As a result, the line-of-credit balance increased by $2.4 million from last June while the total principal amount of long-term notes payable for Roanoke Gas increased by $7,000,000 reflecting the issuance of the new note. The remaining $1,924,000 increase in long-term notes payable is attributable to the borrowing under Midstream's credit facility to finance investment in the MVP.expenditure bridge financing. The Company will continue to use the line-of-credit for bridge financing ~~for its capital expenditures~~ and will evaluate the need and timing to convert additional portions of this debt to more permanent financing. ~~The~~On October 2, 2017, the Company ~~will also continue to draw against the Midstream credit facility and issue additional common stock to finance the MVP project.~~

~~On May 18, 2017, Roanoke Gas entered into an Agreement with Prudential Investment Management to issue~~issued two 10-year unsecured notes in the aggregate principal amount of ~~$8,000,000. These notes are scheduled to be issued on October 2, 2017. The notes will have a 10-year term, from the date of issue,~~$8,000,000 with a ~~3.58%~~ fixed interest rate of ~~interest.~~3.58% per annum. Interest is paid semi-annually on these notes in April and October of each year until the notes mature. The ~~Company will use the~~ proceeds from these notes were used to refinance a portion of ~~its borrowings~~the line-of-credit balance into longer-term financing.

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

On March 27, 2017, Roanoke Gas entered into a new revolving line-of-credit note agreement. The new line-of-credit agreement is for a two-year term expiring March 31, 2019, replacing the prior one-year agreement that expired on March 31, 2017. As the new agreement is for a two-year term, amounts drawn against the new agreement are considered to be non-current as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-month period. Therefore, the balance sheet at June 30, 2017 reflects the line-of-credit balance as part of long-term debt while the outstanding balance of the line-of-credit at September 30, 2016 is classified as a current liability. Except for the two-year term, the new agreement maintains the same variable interest rate based on 30-day LIBOR plus 100 basis points and availability fee of 15 basis points applied to the unused balance on the note. The ~~new~~ 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 ~~new~~ agreement range from $10,000,000 to $30,000,000. As the agreement is for a two-year term, amounts drawn against the new agreement are considered to be non-current, as the balance outstanding under the line-of-credit will not be subject to repayment within the next 12-month period. As long as the multi-tiered borrowing limits under the line of credit remain above the outstanding balance over the succeeding 12 month period, the line-of-credit balance is classified as non-current. However, the borrowing limits on the line-of-credit decline to $17,000,000 effective March 1, 2018, thereby resulting in $54,377 of the line-of-credit balance to be reclassified to a current liability. The Company is currently in discussions to extend the current agreement by one year prior to the end of March when the outstanding balance on the line-of-credit would be classified as current. The Company anticipates being able to extend or replace the line-of-credit ~~agreement on or prior to expiration;~~agreement; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.

RGC RESOURCES, INC. AND SUBSIDIARIES

At ~~June 30,~~December 31, 2017, the Company’s consolidated long-term capitalization including the line-of-credit was ~~53%~~47% equity and ~~47%~~53% debt.

RGC RESOURCES, INC. AND SUBSIDIARIES

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At ~~June 30,~~December 31, 2017, the Company had ~~$10,516,426~~$17,054,377 outstanding under its variable rate line-of-credit with an average balance outstanding during the ~~nine-month~~three-month period of ~~$10,387,806.~~$13,425,938. The Company also had ~~$7,000,000~~$7,576,200 outstanding under a 5-year ~~variable rate term loan and $5,320,200 outstanding under a 5-year variable rate~~variable-rate term credit facility. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable-rate debt outstanding during the period would have resulted in an increase in annual interest expense ~~for the current year~~ of approximately ~~$158,500.~~$52,500. The Company's other long-term debt is at fixed ~~rates.~~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~~September 30, 2017, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had ~~1,711,610~~2,117,098 decatherms of gas in storage, including LNG, at an average price of ~~$3.18~~$3.26 per decatherm, compared to ~~1,552,126~~1,959,449 decatherms at an average price of ~~$2.77~~$2.97 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, as any additional costs or benefits associated with the settlement of derivative contracts and other price hedging techniques are passed through to customers when realized through the PGA mechanism.

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,~~December 31, 2017, 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,~~December 31, 2017.

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,~~December 31, 2017, 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

No changes.

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

None.

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 – OTHER INFORMATION

None.

ITEM 6 – EXHIBITS



Number		Description
10.1		~~Private Shelf Agreement~~ Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and ~~Prudential Investment Management, Inc. for the pre-authorization to issue notes up to $29,500,000 in total during the term~~PRUCO Life Insurance Company of ~~the agreement following proper notice and compliance with the provisions of the Agreement.~~
~~10.2~~		~~Agreement by and between Roanoke Gas Company and Prudential Investment Management for the issuance of $8,000,000 in notes in~~New Jersey, dated October 2, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on ~~May 23,~~October 4, 2017)
10.2		Unsecured Note in the original principal amount of $4,000,000 by and between Roanoke Gas Company and Prudential Arizona Reinsurance Captive Company, dated October 2, 2017 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 4, 2017)
10.3		Unconditional Guaranty Agreement by and between RGC Resources, Inc. and Prudential Investment Management and each Prudential Affiliate which is a party to the borrowings (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on October 4, 2017)
10.4		Private Shelf Agreement by and between Roanoke Gas Company and Prudential Investment Management and affiliates which become bound by this agreement dated September 30, 2015 and First Amendment to the Private Shelf Agreement which extends the expiration date until October 2, 2020 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on October 4, 2017)
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,~~December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at ~~June 30,~~December 31, 2017 and September 30, ~~2016,~~2017, (ii) Condensed Consolidated Statements of Income for the three months ~~and six months~~ ended ~~June 30,~~December 31, 2017 and 2016; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months ~~and nine months~~ ended ~~June 30,~~December 31, 2017 and 2016; (iv) Condensed Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~June 30,~~December 31, 2017 and 2016, 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 4, 2017~~February 8, 2018	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Secretary, Treasurer and CFO



	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2016	$	(2,497,231	)
Other comprehensive income	192,809
Balance at June 30, 2017	$	(2,304,422	)



	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Components of net periodic pension cost:
Service cost	$	176,669		$	173,594		$	530,007		$	520,782
Interest cost	248,900			283,194			746,700			849,582
Expected return on plan assets	(404,103		)	(373,060		)	(1,212,309		)	(1,119,180		)
Recognized loss	165,545			125,420			496,635			376,260
Net periodic pension cost	$	187,011		$	209,148		$	561,033		$	627,444