Document



	Unaudited
	March 31, 2017			September 30, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	546,101		$	643,252
Accounts receivable (less allowance for uncollectibles of $267,227 and $76,934, respectively)	10,316,034			3,478,983
Materials and supplies	972,668			824,139
Gas in storage	2,143,182			7,436,785
Prepaid income taxes	—			1,550,836
Other	1,643,506			1,548,329
Total current assets	15,621,491			15,482,324
UTILITY PROPERTY:
In service	191,604,793			185,577,286
Accumulated depreciation and amortization	(58,191,332		)	(56,156,287		)
In service, net	133,413,461			129,420,999
Construction work in progress	8,118,092			2,707,139
Utility plant, net	141,531,553			132,128,138
OTHER ASSETS:
Regulatory assets	14,425,280			14,332,451
Investment in unconsolidated affiliate	5,189,876			3,496,404
Fair value of marked-to-market transactions	158,988			—
Other	138,617			113,532
Total other assets	19,912,761			17,942,387
TOTAL ASSETS	$	177,065,805		$	165,552,849



	Unaudited
	March 31, 2017			September 30, 2016
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Line-of-credit	$	—		$	14,556,785
Dividends payable	1,047,671			970,244
Accounts payable	5,617,488			5,345,575
Capital contributions payable	883,065			287,794
Customer credit balances	620,062			1,605,608
Income taxes payable	1,813,368			—
Customer deposits	1,651,350			1,627,105
Accrued expenses	2,582,616			3,194,255
Over-recovery of gas costs	4,336,053			909,687
Total current liabilities	18,551,673			28,497,053
LONG-TERM DEBT:
Notes payable	41,896,200			33,896,200
Line-of-credit	8,460,578			—
Less unamortized debt issuance costs	(260,445		)	(260,149		)
Long-term debt net of unamortized debt issuance costs	50,096,333			33,636,051
DEFERRED CREDITS AND OTHER LIABILITIES:
Asset retirement obligations	5,806,689			5,682,556
Regulatory cost of retirement obligations	9,803,684			9,348,443
Benefit plan liabilities	13,626,044			13,763,820
Deferred income taxes	19,227,581			18,957,854
Total deferred credits and other liabilities	48,463,998			47,752,673
STOCKHOLDERS’ EQUITY:
Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 7,224,429 and 7,182,434, respectively	36,122,145			23,941,445
Preferred stock, no par, authorized 5,000,000 shares; no shares issued and outstanding	—			—
Capital in excess of par value	81,202			9,509,548
Retained earnings	26,069,565			24,713,310
Accumulated other comprehensive loss	(2,319,111		)	(2,497,231		)
Total stockholders’ equity	59,953,801			55,667,072
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	177,065,805		$	165,552,849



	Three Months Ended March 31,				Six Months Ended March 31,
	2017		2016		2017		2016
OPERATING REVENUES:
Gas utilities	$	21,662,624	$	21,569,485	$	40,174,957	$	37,355,334
Other	237,389		208,288		513,641		432,495
Total operating revenues	21,900,013		21,777,773		40,688,598		37,787,829
COST OF SALES:
Gas utilities	10,936,248		11,024,458		20,183,100		18,204,292
Other	134,035		104,046		284,863		196,152
Total cost of sales	11,070,283		11,128,504		20,467,963		18,400,444
GROSS MARGIN	10,829,730		10,649,269		20,220,635		19,387,385
OTHER OPERATING EXPENSES:
Operations and maintenance	3,193,526		3,376,496		6,585,354		6,807,729
General taxes	481,268		443,614		922,342		867,601
Depreciation and amortization	1,565,729		1,384,845		3,141,457		2,769,689
Total other operating expenses	5,240,523		5,204,955		10,649,153		10,445,019
OPERATING INCOME	5,589,207		5,444,314		9,571,482		8,942,366
Equity in earnings of unconsolidated affiliate	93,625		33,846		178,165		55,383
Other expense, net	10,570		28,436		14,282		32,309
Interest expense	469,480		415,940		928,001		824,296
INCOME BEFORE INCOME TAXES	5,202,782		5,033,784		8,807,364		8,141,144
INCOME TAX EXPENSE	1,977,583		1,922,337		3,349,947		3,106,907
NET INCOME	$	3,225,199	$	3,111,447	$	5,457,417	$	5,034,237
BASIC EARNINGS PER COMMON SHARE	$	0.45	$	0.44	$	0.76	$	0.71
DILUTED EARNINGS PER COMMON SHARE	$	0.45	$	0.44	$	0.76	$	0.71
DIVIDENDS DECLARED PER COMMON SHARE	$	0.1450	$	0.1350	$	0.2900	$	0.2700



	Three Months Ended March 31,				Six Months Ended March 31,
	2017		2016		2017		2016
NET INCOME	$	3,225,199	$	3,111,447	$	5,457,417	$	5,034,237
Other comprehensive income, net of tax:
Interest rate swap	3,508		—		98,636		—
Defined benefit plans	39,742		34,289		79,484		68,578
OTHER COMPREHENSIVE INCOME, NET OF TAX	43,250		34,289		178,120		68,578
COMPREHENSIVE INCOME	$	3,268,449	$	3,145,736	$	5,635,537	$	5,102,815



	Six Months Ended March 31,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	5,457,417		$	5,034,237
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	3,202,180			2,830,149
Cost of removal of utility plant, net	(145,543		)	(216,214		)
Stock option grants	49,188			43,092
Equity in earnings of unconsolidated affiliate	(178,165		)	(55,383		)
Changes in assets and liabilities which used cash, exclusive of changes and noncash transactions shown separately	3,259,071			3,276,992
Net cash provided by operating activities	11,644,148			10,912,873
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant and nonutility property	(11,397,451		)	(8,164,000		)
Investment in unconsolidated affiliate	(920,036		)	(1,630,098		)
Proceeds from disposal of equipment	9,639			316
Net cash used in investing activities	(12,307,848		)	(9,793,782		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of notes payable	8,000,000			1,932,200
Borrowings under line-of-credit agreement	21,425,539			18,975,610
Repayments under line-of-credit agreement	(27,521,746		)	(20,863,175		)
Debt issuance expenses	(16,674		)	(101,619		)
Proceeds from issuance of stock (41,995 and 37,430 shares, respectively)	698,922			527,410
Cash dividends paid	(2,019,492		)	(1,875,447		)
Net cash provided by (used in) financing activities	566,549			(1,405,021		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(97,151		)	(285,930		)
BEGINNING CASH AND CASH EQUIVALENTS	643,252			985,234
ENDING CASH AND CASH EQUIVALENTS	$	546,101		$	699,304
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	840,843		$	748,447
Income taxes paid	(175,000		)	81,000

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly Resources financial position as of March 31, 2017 and the results of its operations, cash flows and comprehensive income for the three months and six months ended March 31, 2017 and 2016. The results of operations for the three months and six months ended March 31, 2017 are not indicative of the results to be expected for the fiscal year ending September 30, 2017 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. The September 30, 2016 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.

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 March 31, 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 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") as an effort to provide industry-specific guidance. Some of the implementation issues identified by the Task Force include accounting for contributions in aid of construction and assessing collectability of customers when regulated mechanisms exist in which the utility can recover uncollected accounts from ratepayers. The Company will consider all current and future guidance in completing its implementation of the revenue recognition standard.

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 the process of compiling an 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. Although management has not completed its evaluation of the new guidance, 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 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 disclosure presentation, therefore 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 pertinent 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 one is presented, outside a subtotal of income from operations. If a separate line item or items are used to present the other components of net benefit cost, that line item or items must be

appropriately described; furthermore, if a separate line item or items are not used, the line item or items used to present the other components of net benefit cost must be disclosed. 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. 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. Further discussion with the Company's regulatory body will be necessary to determine 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 will have a material effect on the Company's consolidated financial statements when adopted.

On January 17, 2017, Resources Board of Directors approved a three-for-two stock split of the Company's issued and outstanding common stock. The stock split was effected in the form 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. As the par value 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 retrospectively to reflect the 50% stock dividend.

On June 30, 2016, the Company filed with the SCC an application for a modification to the SAVE (Steps to Advance Virginia's Energy) Plan and Rider. The original SAVE Plan has been modified each year to incorporate certain changes and to include new projects that qualify for rate recovery under the Plan. The SAVE Plan provides a mechanism for the Company to recover the related depreciation and expenses and a return on rate base of the additional capital investment related to the modernization of aging natural gas infrastructure without the filing of a formal application for an increase in non-gas base rates. On October 18, 2016, the Company received approval of its application for a modification to the SAVE Plan and Rider. Under the order, the SCC approved the extension of the SAVE Plan for an additional three years through 2021, the replacement of three gas custody transfer stations and the replacement of coated steel tubing services in addition to the existing plan to replace pre-1973 plastic pipe.

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 investment of approximately $35 million, by periodic capital contributions throughout the design and construction phases of the project. Midstream held an approximate $5.2 million equity method investment in the LLC at March 31, 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 March 31, 2017, the Company had $883,065 remaining to be paid under the most recent notice. The capital contribution payable has been reflected on the Company's balance sheet as of March 31,

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 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.

On March 27, 2017, Roanoke Gas entered into a new unsecured line-of-credit agreement. This new line-of-credit agreement replaced the agreement scheduled to expire 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 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.

On November 1, 2016, Roanoke Gas entered into a 5-year unsecured note with Branch Banking & Trust in the principal amount of $7,000,000. The note is variable rate with interest based on 30-day LIBOR plus 90 basis points. In addition, Roanoke Gas also entered into a swap agreement to convert 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.



	March 31, 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	$	168,946	$	30,500,000	$	173,773
Unsecured term note payable, at 30-day LIBOR plus 0.90%, due November 1, 2021	7,000,000		15,285		—		—
RGC Midstream, LLC:
Unsecured term notes payable, at 30-day LIBOR plus 1.60%, due December 29, 2020	4,396,200		76,214		3,396,200		86,376
Total notes payable	$	41,896,200	$	260,445	$	33,896,200	$	260,149
Line-of-credit, at 30-day LIBOR plus 1.00%, due March 31, 2019	$	8,460,578	$	—	$	—	$	—
Total long-term debt	$	50,356,778	$	260,445	$	33,896,200	$	260,149



	Before-Tax Amount		Tax (Expense) or Benefit			Net-of-Tax Amount
Three Months Ended March 31, 2017
Interest rate swaps:
Unrealized gains	$	5,654	$	(2,146	)	$	3,508
Defined benefit plans:
Amortization of actuarial losses	$	64,058	$	(24,316	)	$	39,742
Other comprehensive income	$	69,712	$	(26,462	)	$	43,250
Three Months Ended March 31, 2016
Interest rate swaps:
Unrealized gains	$	—	$	—		$	—
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
Six Months Ended March 31, 2017
Interest rate swaps:
Unrealized gains	$	158,988	$	(60,352	)	$	98,636
Defined benefit plans:
Amortization of actuarial losses	$	128,116	$	(48,632	)	$	79,484
Other comprehensive income	$	287,104	$	(108,984	)	$	178,120
Six Months Ended March 31, 2016
Interest rate swaps:
Unrealized gains	$	—	$	—		$	—
Defined benefit plans:
Amortization of actuarial losses	110,536		(41,958		)	68,578
Other comprehensive income	$	110,536	$	(41,958	)	$	68,578

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.

Basic earnings per common share for the three months and six months ended March 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 March 31,				Six Months Ended March 31,
	2017		2016		2017		2016
Net Income	$	3,225,199	$	3,111,447	$	5,457,417	$	5,034,237
Weighted average common shares	7,215,329		7,139,877		7,204,847		7,131,100
Effect of dilutive securities:
Options to purchase common stock	29,516		5,970		22,647		5,908
Diluted average common shares	7,244,845		7,145,847		7,227,494		7,137,008
Earnings Per Share of Common Stock:
Basic	$	0.45	$	0.44	$	0.76	$	0.71
Diluted	$	0.45	$	0.44	$	0.76	$	0.71

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						Six Months Ended
	March 31,						March 31,
	2017			2016			2017			2016
Components of net periodic pension cost:
Service cost	$	176,669		$	173,594		$	353,338		$	347,188
Interest cost	248,900			283,194			497,800			566,388
Expected return on plan assets	(404,103		)	(373,060		)	(808,206		)	(746,120		)
Recognized loss	165,545			125,420			331,090			250,840
Net periodic pension cost	$	187,011		$	209,148		$	374,022		$	418,296



	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2017			2016			2017			2016
Components of postretirement benefit cost:
Service cost	$	45,817		$	37,005		$	91,634		$	74,010
Interest cost	156,706			156,145			313,412			312,290
Expected return on plan assets	(142,878		)	(126,965		)	(285,756		)	(253,930		)
Recognized loss	107,440			62,543			214,880			125,086
Net postretirement benefit cost	$	167,085		$	128,728		$	334,170		$	257,456

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.



			Fair Value Measurements - March 31, 2017
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Interest rate swap	$	158,988	$	—	$	158,988	$	—
Total	$	158,988	$	—	$	158,988	$	—

Liabilities:
Natural gas purchases	$	1,004,777	$	—	$	1,004,777	$	—
Total	$	1,004,777	$	—	$	1,004,777	$	—

			Fair Value Measurements - September 30, 2016
	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas purchases	$	1,052,930	$	—	$	1,052,930	$	—
Total	$	1,052,930	$	—	$	1,052,930	$	—

Under the asset management contract, a timing difference can exist between the payment for natural gas purchases and the actual receipt of such purchases. Payments are made based on a predetermined monthly volume with the price based on weighted average first of the month index prices corresponding to the month of the scheduled payment. At March 31, 2017 and September 30, 2016, 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 carrying value of cash and cash equivalents, accounts receivable, accounts payable (with the exception of the timing difference under the asset management contract), customer credit balances and customer deposits is a reasonable estimate of fair value due to the short-term nature of these financial instruments. In addition, the carrying amount of the variable rate line-of-credit is a reasonable approximation of its fair value. The following table summarizes the fair value of the Company’s financial assets and liabilities that are not adjusted to fair value in the financial statements as of March 31, 2017 and September 30, 2016:



			Fair Value Measurements - March 31, 2017
	Carrying Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Long-term debt - notes payable	$	41,896,200	$	—	$	—	$	42,579,357
Total	$	41,896,200	$	—	$	—	$	42,579,357

			Fair Value Measurements - September 30, 2016
	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
Total	$	33,896,200	$	—	$	—	$	36,163,523

FASB ASC 825, Financial Instruments, requires disclosures regarding concentrations of credit risk from financial instruments. Cash equivalents are investments in high-grade, short-term securities (original maturity less than three months), placed with financially sound institutions. Accounts receivable are from a diverse group of customers including individuals and small and large companies in various industries. As of March 31, 2017 and September 30, 2016, 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.

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 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.

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 60,800 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”).

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

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

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

The Company's approved billing rates include a component designed to allow for the recovery of the cost of natural gas used by its customers. The cost of natural gas is considered a pass-through cost and is independent of the non-gas rates of the Company. This rate component, referred to as the PGA, allows the Company to pass along to its customers increases and decreases in natural gas costs incurred by its regulated operations. On a quarterly basis, 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 and six months ended March 31, 2017, the Company accrued approximately $982,000 and $1,605,000 in additional revenue and margin for weather that was nearly 20% and 18% warmer than normal, respectively. For the same periods last year, the Company accrued approximately $105,000 and $1,181,000 in additional revenue and margin for weather that was 1% and 13% warmer than normal.

The Company also has an approved rate structure in place that mitigates the impact of financing costs associated with its natural gas inventory. Under this rate structure, Roanoke Gas recognizes revenue for the financing costs, or “carrying costs,” of its investment in natural gas inventory. This ICC factor applied to the cost of inventory is based on the Company’s weighted-average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes ICC revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. In addition, ICC revenues are impacted by the changes in the weighting of the components that are used to determine the weighted-average cost of capital. The average unit price of gas in storage during the first six months of the current fiscal year was $0.41 per decatherm, or 12%, lower than the same period last year, as the Company benefited from lower natural gas commodity prices during the summer storage refill period in calendar 2016. 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 spring and summer months.

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 and Rider, 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 years and the level of capital investment continues to grow, SAVE Plan revenues have continued to increase. The Company recognized approximately $922,000 and $1,803,000 in SAVE Plan revenues for the three-month and six-month periods ended March 31, 2017, compared to $576,000 and $1,037,000 for the same periods 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.



	Three Months Ended March 31,
	2017		2016		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	21,662,624	$	21,569,485	$	93,139		—	%
Other	237,389		208,288		29,101			14	%
Total Operating Revenues	$	21,900,013	$	21,777,773	$	122,240		1	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	2,593,971		3,155,915		(561,944		)	(18	)%
Transportation and Interruptible	791,038		796,581		(5,543		)	(1	)%
Total Delivered Volumes	3,385,009		3,952,496		(567,487		)	(14	)%
Heating Degree Days (Unofficial)	1,681		2,070		(389		)	(19	)%

Total operating revenues for the three months ended March 31, 2017, compared to the same period last year, increased due to higher SAVE Plan revenues and natural gas commodity prices partially offset by lower customer deliveries. As discussed 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. Furthermore, the commodity price of natural gas increased by nearly 18% 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 much warmer weather during the quarter, weather sensitive residential and commercial sales volumes declined by 18% with total natural gas deliveries declining by 14%. The Company was able to recover much of the lost margin attributable to warmer weather through the WNA mechanism. Transportation and industrial volumes were nearly unchanged from the same quarter last year.

Regulated natural gas margins from utility operations increased from the same period last year primarily as a result of higher SAVE Plan revenues and customer growth. SAVE revenues increased by $346,838 due to the increasing investment in SAVE related projects. Volumetric margin, net of the WNA adjustment, actually decreased by $156,110 or 2.3%. Even though the Company experienced some customer growth, WNA adjusted volumes decreased by 2.5%. Increases in customer base charge from customer growth and other gas revenues were offset by a reduction in ICC revenues. Other margins were nearly unchanged from last year.

Operation and maintenance expenses declined by $182,970, or 5% from the same period last year. Increases in capitalized overheads and lower corporate property and liability insurance premiums more than offset increases in employee benefits and other costs. The Company capitalized $247,000 more in overheads related to an 82% increase in capital expenditures. The increased level of capital spending is attributable to the Company's ongoing infrastructure modernization program, new business and the installation of an automated meter reading system. The Company experienced a reduction of $49,000 in corporate property and liability insurance cost on favorable policy renewals. Employee benefit costs increased by more than $32,000 due to increased health insurance premiums and higher actuarial determined retirement plan costs. Operations labor costs increased by $53,000, or 4%, related to work assignments and normal salary adjustments. The remaining differences were related to various minor fluctuations in other expenses.

Equity in earnings of unconsolidated affiliate increased by $59,779, or 177%, due to the increasing investment in the Mountain Valley Pipeline ("MVP") project. This project began in the first quarter of fiscal 2016 and 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.



	Six Months Ended March 31,
	2017		2016		Increase (Decrease)			Percentage
Operating Revenues
Gas Utilities	$	40,174,957	$	37,355,334	$	2,819,623		8	%
Other	513,641		432,495		81,146			19	%
Total Operating Revenues	$	40,688,598	$	37,787,829	$	2,900,769		8	%
Delivered Volumes
Regulated Natural Gas (DTH)
Residential and Commercial	4,535,468		4,701,784		(166,316		)	(4	)%
Transportation and Interruptible	1,484,036		1,499,163		(15,127		)	(1	)%
Total Delivered Volumes	6,019,504		6,200,947		(181,443		)	(3	)%
Heating Degree Days (Unofficial)	2,968		3,152		(184		)	(6	)%

Total operating revenues for the six months ended March 31, 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 a reduction in delivered volumes. SAVE Plan revenues increased by $766,111 as investments in SAVE related projects continued. The commodity price for natural gas increased by 18% 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 3% due to warmer weather, as evidenced by the 6% reduction in heating degree days. Residential and commercial volumes

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 $766,111 due to the increasing investment in SAVE related projects. Volumetric margin, net of the WNA adjustment, increased by $110,732 as a result of a 1% increase in WNA adjusted volumes. The increase in net volumetric margin is attributable to customer growth and the WNA adjustment. Increases in customer base charges and other gas revenues were more than offset by reductions in ICC revenues. Other margins experienced a small decline from last year's levels.

Operation and maintenance expenses declined by $222,375, or 3%, from the same period last year. As noted for the quarter, increased capitalized overheads and lower corporate property and liability insurance premiums were the primary catalysts for the reduction in expense. Capitalized construction overheads increased by more than $313,000 as direct capital expenditures increased by 61% during the current period. The combination of the ongoing pipeline renewal program and the automated meter reading system project accounted for the increased capital spending. Corporate property and liability insurance premiums declined by $102,000 due to improvements in the insurance market. These expense reductions were partially offset by higher employee benefit costs and operations labor. Employee benefit costs increased by more than $115,000 due to increased health insurance premiums and higher actuarial determined retirement plan costs and operations labor expense increased by $75,000. The remaining differences were related to various minor fluctuations in other expenses.

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

The Company considers an estimate to be critical if it is material to the financial statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. There have been no 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.

Roanoke Gas uses a third party asset manager to manage its pipeline transportation and 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 2018. The Company expects to bid, negotiate and have in place a new asset management agreement by the expiration date of the current agreement.

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 gathering and transmission system in northern West Virginia to another interstate pipeline in south central Virginia. This project falls under the jurisdiction of FERC and is subject to its approval prior to beginning construction. In 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"), and on September 16, 2016, FERC issued its draft environmental impact statement ("EIS") regarding the MVP. In the draft EIS, FERC staff concluded that approval of the MVP would result in some adverse environmental impacts; however, they acknowledged that such impacts would be reduced to less than significant levels with the implementation of the LLC's proposed mitigation plans in addition to measures recommended in the EIS. FERC issued an updated NOS on March 31, 2017 that indicated issuance of the final EIS in June 2017. Assuming a favorable ruling by FERC, construction of the pipeline is expected to begin later in 2017 with a targeted in-service date of the pipeline by the end of calendar 2018.

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 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 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 for the acquisition of land and materials related to the construction of the pipeline and other pre-construction costs. Once approved 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, with the balance coming from equity capital.

A majority of the earnings from the investment in MVP relates 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, construction on the pipeline should 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.

The Company continues to recover the costs of its infrastructure replacement program through its SAVE Plan. On June 30, 2016, the Company filed an application with the SCC for modification to its SAVE Plan. The original SAVE Plan was approved by the SCC through an order issued on August 29, 2012 and has been modified or amended each year since. The original SAVE Plan was 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 expenses and return on rate base of the additional capital investment without the filing of a formal application for an increase in non-gas base rates. 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 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 application included provisions to continue the ongoing pipeline renewal project with a focus on pre-1973 plastic pipe, the replacement of three natural gas custody transfer stations and the replacement of coated steel tubing services and related meter installations. The 2017 SAVE revenue requirement is approximately $4,000,000, representing an increase of almost $1,000,000 over the estimated 2016 SAVE Plan year. The additional SAVE Plan revenue as approved by the SCC will allow the Company to forgo a formal non-gas rate increase application at this time. The Company is in the process of preparing its 2018 SAVE Plan year filing.

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.

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 generally driven by net income, depreciation and reductions in natural gas storage inventory during the first six months of the fiscal year. Cash flow provided by operations increased from the same period last year by $731,275, primarily due to a greater increase in net income, depreciation and over-collection of gas costs. Accounts receivable activity is generally a use of cash during the first half of the fiscal year as balances increase due to higher sales during the heating months. Accounts receivable balances increased by a larger amount during the current period due to higher gas costs included in the billing rates for March compared to the prior year. Correspondingly, the higher gas costs also resulted in a much smaller decline in accounts payable balances. A summary of the cash provided by operations is listed below:



	Six Months Ended March 31,
Cash Flow From Operating Activities:	2017			2016			Increase (Decrease)
Net income	$	5,457,417		$	5,034,237		$	423,180
Depreciation	3,202,180			2,830,149			372,031
Increase in over-collections	3,426,366			2,861,834			564,532
Decrease in gas in storage	5,293,603			5,263,846			29,757
Increase in accounts receivable	(7,027,343		)	(5,346,100		)	(1,681,243		)
Decrease in accounts payable	(220,954		)	(1,071,032		)	850,078
Other	1,512,879			1,339,939			172,940
Net Cash Provided by Operations	$	11,644,148		$	10,912,873		$	731,275

Investing activities are generally composed of expenditures related to investment in the Company's utility plant projects, which primarily involves 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 its bare steel and cast iron pipe during the prior quarter and is now focused on continued SAVE infrastructure replacement projects including the replacement of approximately 45 miles of pre-1973 first generation plastic pipe and upgrades to three natural gas transfer stations. Total capital expenditures for additions to property during the first six months of the year were $11.4 million, which represented more than a $3.2 million increase over the same period last year. The increase is attributable to the Company's expenditures for installing 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 the current fiscal year. The AMR project does not qualify as a SAVE project subject to immediate recovery of the related investment costs and expenses; however, the Company expects future cost savings through significantly reduced meter reading and billing costs. The combination of the AMR and SAVE related projects have resulted in a projected fiscal 2017 capital budget of more than $20 million. Operating cash flows and additional corporate borrowings are expected to provide the majority of the funding for these projects.

Investing cash flows also reflect the Company's continued funding of its participation in the MVP, with a total cash investment of $920,036 for the six months ended March 31, 2017. The level of investment in the MVP has moderated as most of the pre-construction activities have been completed and FERC approval of the project is not expected until summer. If approved, the Company expects to invest an estimated total 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.

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 $566,549 for the current period compared to $1,405,021 for the same period last year. The nearly $2 million swing is attributable to the additional borrowing required to support the increased capital expenditures noted above. The primary difference in financing activities between 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 were used to convert a portion of the line-of-credit balance supporting Roanoke Gas' capital expenditures into a longer-term financing instrument. As a result, the line-of-credit balance increased slightly from last March 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 $1,000,000 increase in long-term notes payable is attributable to the borrowing under Midstream's credit facility to finance investment in the MVP. 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 Company will also continue to draw against the Midstream credit facility to finance the MVP project.

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, which replaced the prior one-year agreement scheduled to expire 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 March 31, 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, t

he 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. The Company anticipates being able to extend or replace the line-of-credit agreement on or prior to expiration; however, there is no guarantee that the line-of-credit agreement will be extended or replaced on terms comparable to those currently in place.

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.

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At March 31, 2017, the Company had $8,460,578 outstanding under its variable rate line-of-credit with an average balance outstanding during the six-month period of $11,751,314. The Company also had $7,000,000 outstanding under a 5-year variable rate term loan and $4,396,200 outstanding under a 5-year variable rate term credit facility. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable-rate debt outstanding during the period would have resulted in an increase in interest expense for the current period of approximately $108,676. The Company's other long-term debt is at fixed rates.

At March 31, 2017, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 671,479 decatherms of gas in storage, including LNG, at an average price of $3.19 per decatherm, compared to 815,122 decatherms at an average price of $3.55 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.

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to be effective in providing reasonable assurance that information required to be disclosed in reports under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to management to allow for timely decisions regarding required disclosure.

As of March 31, 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 March 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 March 31, 2017, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.



Number		Description
10.1		Revolving Line of Credit Note in the original principal amount of $30,000,000 by Roanoke Gas Company in favor of Wells Fargo Bank, N.A. dated as of March 27, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on March 29, 2017).
10.2		First Amendment to Credit Agreement by and between Roanoke Gas Company and Wells Fargo Bank, N.A. dated as of March 27, 2017 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on March 29, 2017).
10.3		RGC Resources, Inc. Restricted Stock Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on February 9, 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 March 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets at March 31, 2017 and September 30, 2016, (ii) Condensed Consolidated Statements of Income for the three months and six months ended March 31, 2017 and 2016; (iii) Condensed Consolidated Statements of Comprehensive Income for the three months and six months ended March 31, 2017 and 2016; (iv) Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2017 and 2016, and (v) Condensed Notes to Condensed Consolidated Financial Statements.




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)



Large accelerated filer	¨	Accelerated filer	ý

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨



Class		Outstanding at April 30, 2017
Common Stock, $5 Par Value		7,225,315



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



	Three Months Ended March 31,
	2017		2016		Increase (Decrease)
Customer Base Charge	$	3,134,398	$	3,115,508	$	18,890
Carrying Cost	101,986		131,438		(29,452		)
SAVE Plan	922,344		575,506		346,838
Volumetric	5,556,428		6,589,678		(1,033,250		)
WNA	982,375		105,235		877,140
Other Gas Revenues	28,845		27,662		1,183
Total	$	10,726,376	$	10,545,027	$	181,349



Balance Sheet Location of Other Investments:	March 31, 2017		September 30, 2016
Other Assets:
Investment in unconsolidated affiliate	$	5,189,876	$	3,496,404



	Three Months Ended				Six Months Ended
Income Statement Location of Other Investments:	March 31, 2017		March 31, 2016		March 31, 2017		March 31, 2016
Equity in earnings of unconsolidated affiliate	$	93,625	$	33,846	$	178,165	$	55,383



	March 31, 2017	September 30, 2016
Derivative designated as hedging instrument:
Interest rate swap	$158,988	—



	Accumulated Other Comprehensive Income (Loss)
Balance at September 30, 2016	$	(2,497,231	)
Other comprehensive income	178,120
Balance at March 31, 2017	$	(2,319,111	)



*	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.

Date: May 5, 2017	By:	/s/ Paul W. Nester
		Paul W. Nester
		Vice President, Secretary, Treasurer and CFO


1.	Basis of Presentation


2.	Stock Split


3.	Rates and Regulatory Matters


5.	Derivatives and Hedging