10-K 1 d72151d10k.htm 10-K 10-K
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended September 30, 2015   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 Avenue, N.E., Roanoke, VA   24016
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code (540) 777-4427

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

 

Title of Each Class

 

Name of Each Exchange on

Which Registered

Common Stock, $5 Par Value   NASDAQ Global Market

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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  x    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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨  (Do not check if smaller reporting company)    Smaller reporting company   ¨

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

State the aggregate market value of the voting and non voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity as of the last business day of the registrant’s most recently completed second fiscal quarter: March 31, 2015. $89,254,811

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

 

Class

 

Outstanding at November 30, 2015

COMMON STOCK, $5 PAR VALUE   4,750,645 SHARES

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the RGC Resources, Inc. Proxy Statement for the 2016 Annual Meeting of Shareholders are incorporated by reference into Part III hereof.


Table of Contents

TABLE OF CONTENTS

 

               Page Number  
      Cautionary Note Regarding Forward Looking Statements      2   

PART I

     
   Item 1.    Business      3   
   Item 1A.    Risk Factors      6   
   Item 1B.    Unresolved Staff Comments      10   
   Item 2.    Properties      10   
   Item 3.    Legal Proceedings      10   
   Item 4.    Mine Safety Disclosures      10   

PART II

        
   Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.      11   
   Item 6.    Selected Financial Data      12   
   Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations      13   
   Item 7A.    Quantitative and Qualitative Disclosures About Market Risk      27   
   Item 8.    Financial Statements and Supplementary Data      28   
   Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosures      60   
   Item 9A.    Controls and Procedures      60   
   Item 9B.    Other Information      63   

PART III

     
   Item 10.    Directors, Executive Officers and Corporate Governance      64   
   Item 11.    Executive Compensation      64   
   Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      64   
   Item 13.    Certain Relationships and Related Transactions, and Director Independence      64   
   Item 14.    Principal Accounting Fees and Services      64   

Part IV

     
   Item 15.    Exhibits and Financial Statement Schedules      65   
   Signatures      66   


Table of Contents

Cautionary Note Regarding 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 announce or 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 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” of this 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.

 

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PART I

 

Item 1. Business.

General and Historical Development

RGC Resources, Inc. (“Resources” or the “Company”) was incorporated in the state of Virginia on July 31, 1998, for the primary purpose of becoming the holding company for Roanoke Gas Company (“Roanoke Gas”) and its subsidiaries. Effective July 1, 1999, Roanoke Gas and its subsidiaries were reorganized into the holding company structure. Resources is currently composed of the following subsidiaries: Roanoke Gas, Diversified Energy Company, RGC Ventures of Virginia, Inc and RGC Midstream, LLC.

Roanoke Gas was organized as a public service corporation under the laws of the Commonwealth of Virginia in 1912. The principal service of Roanoke Gas is the distribution and sale of natural gas to residential, commercial and industrial customers within its service territory in Roanoke, Virginia and the surrounding localities. Roanoke Gas also provides certain non-regulated services which account for most of the non-gas utility revenue of Resources.

In 2000, the information technology department of Resources formed Application Resources, Inc. under RGC Ventures of Virginia, Inc. to provide information technology consulting services. In 2011, the Company also formed The Utility Consultants under RGC Ventures of Virginia, Inc to provide utility and regulatory consulting services to other utilities. The operations of RGC Ventures of Virginia, Inc. contributed less than 6% of other revenues and less than 1% of total revenues of Resources during fiscal 2015. The Utility Consultants portion of RGC Ventures of Virginia, Inc. and Diversified Energy Company currently have no active operations.

In July 2015, the Company formed RGC Midstream, LLC, a limited liability company established for the purpose of becoming a 1% investor in Mountain Valley Pipeline, LLC. Mountain Valley Pipeline, LLC was created for the purpose of constructing a natural gas pipeline in West Virginia and Virginia. Additional information regarding this investment is provided under Note 12 of the Company’s annual consolidated financial statements and under the Equity Investment in Mountain Valley Pipeline section of Item 7.

Services

Roanoke Gas maintains an integrated natural gas distribution system to deliver natural gas purchased from suppliers to residential, commercial and industrial users in its service territory. The schedule below is a summary of customers, delivered volumes (expressed in decatherms), revenues and margin as a percentage of the total for each category:

 

     2015  
     Customers     Volume     Revenue     Margin  

Residential

     91.2     40     58     58

Commercial

     8.7     30     33     26

Industrial

     0.1     30     6     11

Other Utility

     0.0     0     1     3

Other Non-Utility

     0.0     0     2     2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Percent

     100.0     100     100     100
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Value

     59,080        9,875,007      $ 68,189,607      $ 30,206,433   
  

 

 

   

 

 

   

 

 

   

 

 

 
     2014  
     Customers     Volume     Revenue     Margin  

Residential

     91.2     40     57     58

Commercial

     8.7     29     34     25

Industrial

     0.1     31     6     12

Other Utility

     0.0     0     1     3

Other Non-Utility

     0.0     0     2     2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Percent

     100.0     100     100     100
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Value

     58,553        10,087,651      $ 75,016,134      $ 29,337,089   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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     2013  
     Customers     Volume     Revenue     Margin  

Residential

     91.2     41     57     58

Commercial

     8.7     28     33     25

Industrial

     0.1     31     6     12

Other Utility

     0.0     0     2     3

Other Non-Utility

     0.0     0     2     2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Percent

     100.0     100     100     100
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Value

     58,238        9,408,894      $ 63,205,666      $ 27,602,891   
  

 

 

   

 

 

   

 

 

   

 

 

 

Roanoke Gas’ regulated natural gas distribution business accounted for approximately 98% of Resources total revenues for fiscal years ending September 30, 2015, 2014 and 2013. The table above indicates that residential customers represent over 91% of the Company’s customer total; however, they represent less than 50% of the total gas volumes delivered and more than half of the Company’s consolidated revenues and margin. Industrial customers include primarily transportation customers that purchase their natural gas requirements directly from a supplier other than the Company and utilize Roanoke Gas’ natural gas distribution system for delivery to their operations. Most of the revenue billed for these customers relates only to transportation service and not to the purchase of natural gas causing total revenues generated by these deliveries to be approximately 6% of total revenues even though they represent 30% of total natural gas deliveries for the year ended September 30, 2015 and approximately 11% to 12% of gross margin for each of the years presented.

The Company’s revenues are affected by changes in gas costs as well as by changes in consumption volume due to weather and economic conditions and changes in the non gas portion of customer billing rates. Increases or decreases in the cost of natural gas are passed on to customers through the purchased gas adjustment mechanism as explained in further detail in Note 1 of the Company’s annual consolidated financial statements. Significant increases in gas costs may cause customers to conserve or, in the case of industrial customers, to switch to alternative energy sources.

The Company’s residential and commercial sales are seasonal and temperature-sensitive as the majority of the gas sold by Resources to these customers is used for heating. For the fiscal year ended September 30, 2015, approximately 68% of the Company’s total DTH of natural gas deliveries and 77% of the residential and commercial deliveries were made in the five-month period of November through March. These percentages are consistent with prior years. Total natural gas deliveries were 9.9 million DTH, 10.1 million DTH and 9.4 million DTH in fiscal 2015, 2014 and 2013, respectively.

Suppliers

Roanoke Gas relies on multiple interstate pipelines including those operated by Columbia Gas Transmission Corporation and Columbia Gulf Transmission Corporation (together “Columbia”), and East Tennessee Natural Gas Company (“East Tennessee”), Tennessee Gas Pipeline, Midwestern Gas Transmission and Saltville Gas Storage Company, LLC to transport natural gas from the production and storage fields to Roanoke Gas’ distribution system. Roanoke Gas is directly served by two pipelines, Columbia and East Tennessee. Columbia historically has delivered between 50% and 60% of the Company’s gas supply, while East Tennessee delivers the balance of the Company’s requirements. The rates paid for natural gas transportation and storage services purchased from the interstate pipeline companies are established by tariffs approved by the Federal Energy Regulatory Commission (“FERC”). These tariffs contain flexible pricing provisions, which, in some instances, authorize these transporters to reduce rates and charges to meet price competition. The current pipeline contracts expire at various times from 2017 to 2020. The Company anticipates being able to renew these contracts or enter into other contracts to meet customers’ continued demand for natural gas.

The Company manages its pipeline contracts and liquefied natural gas storage (“LNG”) facility in order to provide for sufficient capacity to meet the natural gas demands of its customers. The maximum daily winter capacity for delivery into Roanoke Gas’ distribution system under the interstate pipelines is 78,606 DTH per day. The LNG facility, which is capable of storing up to 220,000 DTH of natural gas in a liquid state for use during peak demand, has the capability of providing an additional 33,000 DTH per day. Combined, the pipelines and LNG facility can provide more than 111,000 DTH on a single winter day. In fiscal 2015, the Company realized a maximum one day-customer demand of 91,341 DTH which represented the highest single day volume delivery in the Company’s history.

 

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The Company uses multi-year contracts to meet its natural gas supply needs. The Company currently contracts with Sequent Energy Management, L.P. to manage its pipeline transportation and storage rights and gas supply inventories and deliveries and serve as the primary supplier of natural gas for Roanoke Gas. Natural gas purchased under the asset management agreement is priced at indexed-based market prices as reported in major industry pricing publications. The Company expects its firm supply agreements will be sufficient to meet customer demands for natural gas during the term of the agreement, which expires March 31, 2017.

The Company uses summer storage programs to supplement gas supply requirements during the winter months. During the summer months, the Company injects gas into its LNG facility. In addition, the Company has contracted for storage capacity from Columbia, Tennessee Gas Pipeline and Saltville Gas Storage Company, LLC for a combined total of more than 2.4 million DTH of storage capacity. The balance of the Company’s annual natural gas requirements are met primarily through market purchases made by its asset manager.

Competition

The Company’s natural gas utility operates in a regulated, monopolistic environment. Roanoke Gas currently holds the only franchises and/or certificates of public convenience and necessity to distribute natural gas in its Virginia service areas. These franchises generally extend for multi-year periods and are renewable by the municipalities, including exclusive franchises in the cities of Roanoke and Salem and the Town of Vinton, Virginia, which all expire December 31, 2015.

Management anticipates that the Company will be able to renew all of its franchises when they expire. There can be no assurance, however, that a given jurisdiction will not refuse to renew a franchise or will not, in connection with the renewal of a franchise, attempt to impose restrictions or conditions that could adversely affect the Company’s business operations or financial condition. Certificates of public convenience and necessity, issued by the Virginia State Corporation Commission (the “SCC”), are of perpetual duration, subject to compliance with regulatory standards.

Although Roanoke Gas has exclusive rights for the distribution of natural gas in its service area, the Company competes with suppliers of other energy sources such as fuel oil, electricity, propane, coal and solar. Competition can be intense among the other energy sources and can be based primarily on price. This is particularly true for those industrial applications that have the ability to switch to alternative fuels. The relationship between supply and demand has the greatest impact on the price of natural gas. Greater demand for natural gas for electric generation and other uses can provide upward pressure on the price of natural gas. Currently, a plentiful supply of natural gas, mostly due to new drilling and extraction processes in shale formations, has served to maintain prices at lower levels. The Company continues to see a demand for its product and extends service to the new residential construction markets located along or near gas distribution mains in its service area. Although new construction activity has been limited over the last few years, the Company has been able to grow its customer base through customer conversions from an alternative energy source to natural gas along its distribution lines.

Regulation

In addition to the regulatory requirements generally applicable to all companies, Roanoke Gas is also subject to additional regulation at the federal, state and local levels. At the federal level, the Company is subject to pipeline safety regulations issued by the Department of Transportation and the Pipeline and Hazardous Materials Safety Administration.

At the state level, the SCC performs regulatory oversight including the approval of rates and charges at which natural gas is sold to customers, the approval of agreements between or among affiliated companies involving the provision of goods and services, pipeline safety, and certain other corporate activities of the Company, including mergers and acquisitions related to utility operations. The SCC also grants certificates of public convenience and necessity to distribute natural gas in Virginia.

At the local level, Roanoke Gas is further regulated by the municipalities and localities that grant franchises for the placement of gas distribution pipelines and the operation of gas distribution networks within their jurisdictions.

Employees

At September 30, 2015, Resources had 125 full-time employees and 133 total employees. As of that date, 33 employees, or 26% of the Company’s full-time employees, belonged to the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial International Union, Local No. 515 and were represented under a collective bargaining agreement. The union has been in place at the Company since 1952. The Company and the union successfully negotiated a new collective bargaining agreement during 2015 that will expire on July 31, 2020. Management maintains an amicable relationship with the union.

 

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Website Access to Reports

The Company’s website address is www.rgcresources.com. Information appearing on this website is not incorporated by reference in and is not a part of this annual report. The Company files reports with the Securities and Exchange Commission (“SEC”). A copy of this annual report, as well as other recent annual and quarter reports are available on the Company’s website. You may read and copy these filings with the SEC at the SEC public reference room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding the Company’s filings at www.sec.gov, which is hyper linked on the Company’s website and is where you can obtain other Company filings with the SEC.

 

Item 1A. Risk Factors

Please carefully consider the risks described below regarding the Company. The risks described below are not the only ones faced by the Company. Additional risks not presently known to the Company or that the Company currently believes are immaterial may also impair business operations and financial results. If any of the following risks actually occur, the Company’s business, financial condition or results of operations could be adversely affected. In such case, the trading price of the Company’s common stock could decline and an investor could lose all or part of his, her or its investment.

Increased compliance and pipeline safety requirements and fines.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Working in concert with this commitment are numerous laws and regulations at both the federal and state levels. The Company is subject to ongoing inspections and reviews. Failure to comply with such requirements could result in the levy of significant fines. Recent enforcement actions by the Virginia Division of Utility and Railroad Safety have resulted in increased fines for gas distribution companies across the state. There are inherent risks that may be beyond the Company’s control, including third party actions, which could result in damage to pipeline facilities, injury and even death. Such incidents could subject the Company to lawsuits, large fines, increased scrutiny and loss of customers, all of which could have a significant effect on the Company’s financial position and results of operation.

Availability of adequate and reliable pipeline capacity.

The Company is served directly by two interstate pipelines. These two pipelines carry 100% of the natural gas transported to the Company’s distribution system. Depending on weather conditions and the level of customer demand, failure of one or both of these interstate transmission pipelines could have a major impact on the Company’s ability to meet customer demand for natural gas and adversely affect the Company’s earnings as a result of lost revenue and the cost of service restoration.

Risks associated with the operation of a natural gas distribution pipeline and LNG storage facility.

Numerous potential risks are inherent in the operation of a natural gas distribution system and LNG storage facility including unanticipated or unforeseen events that are beyond the control of the Company. Examples of such events include adverse weather conditions, acts of terrorism, accidents, equipment breakdowns, failure of upstream pipelines and storage facilities, as well as catastrophic events such as explosions, fires, earthquakes, floods, or other similar events. These risks could result in injury or loss of life, property damage, pollution and customer service disruption resulting in potentially significant financial losses. The Company maintains insurance policies with financially sound carriers to protect against many of these risks. If losses result from a risk that is not fully covered by insurance, the Company’s financial condition could be significantly impacted if it were unable to recover such losses from customers through the regulatory rate making process. Even if the Company did not incur a direct financial loss as a result of any of the events noted above, it could encounter significant reputational damage from a reliability, safety, integrity or similar viewpoint, ultimately resulting in a longer-term negative impact on earnings.

 

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Investment in Mountain Valley Pipeline.

The success or failure of the Company’s investment in Mountain Valley Pipeline, LLC (the “LLC”) is predicated on several key factors including but not limited to the ability of all investors to meet their capital calls when due, the timely approval of the pipeline project by FERC, completing the construction of the pipeline within the targeted time frame and budget and fully subscribing the capacity of the pipeline once in service. Any significant delay, cost over-run or the failure to receive the requisite approvals could have a significant effect on the Company’s earnings and financial position.

In addition, there are also numerous risks facing the LLC over time, which in turn could adversely affect the Company’s earnings and financial performance through its 1% investment. The LLC’s ability to complete construction of, and capital improvement to, facilities on schedule and within budget may be adversely affected by escalating costs for materials and labor and regulatory compliance, inability to obtain or renew necessary licenses, rights-of-way, permits or other approvals on acceptable terms or on schedule, disputes involving contractors, labor organizations, land owners, governmental entities, environmental groups, Native American and aboriginal groups, and other third parties, negative publicity, transmission interconnection issues, and other factors. If any development project or construction or capital improvement project is not completed, is delayed or is subject to cost overruns, certain associated costs may not be approved for recovery or recoverable through regulatory mechanisms that may otherwise be available, and the LLC could become obligated to make delay or termination payments or become obligated for other damages under contracts, could experience the loss of tax credits or tax incentives, or delayed or diminished returns, and could be required to write-off all or a portion of its investment in the project. Any of these events could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC may face risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede its development and operating activities. The LLC must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should the LLC be unsuccessful in obtaining necessary licenses or permits on acceptable terms, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on the LLC, the LLC’s business, financial condition, results of operations and prospects could be materially adversely affected. Any failure to negotiate successful project development agreements for new facilities with third parties could have similar results. The LLC’s gas infrastructure facilities and other facilities are subject to many operational risks. Operational risks could result in, among other things, lost revenues due to prolonged outages, increased expenses due to monetary penalties or fines for compliance failures, liability to third parties for property and personal injury damage, a failure to perform under applicable sales agreements and associated loss of revenues from terminated agreements or liability for liquidated damages under continuing agreements. The consequences of these risks could have a material adverse effect on the LLC’s business, financial condition, results of operations and prospects. Uncertainties and risks inherent in operating and maintaining the LLC’s facilities include, but are not limited to, risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned. The LLC’s business, financial condition, results of operations and prospects can be materially adversely affected by weather conditions, including, but not limited to, the impact of severe weather. Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt the LLC’s business, or the businesses of third parties, may materially adversely affect the LLC’s business, financial condition, results of operations and prospects.

Supply disruptions due to weather or other forces.

Hurricanes and other natural or man-made disasters could damage or inhibit production and/or pipeline transportation facilities, which could result in decreased supplies of natural gas. Decreased supplies could result in an inability to meet customer demand leading to higher prices or service disruptions. Disasters could also lead to additional governmental regulations that limit production activity or increase production and transportation costs.

 

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Security breach or cyber-attacks on the Company’s computer systems could corrupt financial information, expose confidential personal information or compromise the safe and reliable delivery of natural gas.

A breach of the Company’s information systems from cyber-attacks or other sources could lead to disruptions in natural gas deliveries or compromise the safety of our distribution system. Such attacks could also result in corruption of the Company’s financial information or the unauthorized release of confidential customer, employee or vendor information. The Company takes reasonable precautions to safeguard its computer systems from attack; however, there is no guarantee that Company processes will adequately protect against unauthorized access to data. In the event of a successful attack, the Company could be exposed to material financial and reputational risks.

General downturn in the economy or prolonged period of slow economic recovery.

A weak or poorly performing economy can negatively affect the Company’s profitability. An economic downturn can result in loss of commercial and industrial customers due to plant closings as well as slow or declining growth in new customer additions, both of which would result in reduced sales volumes and lower revenues. An economic downturn could also result in rising unemployment and other factors that could result in increased customer delinquencies and bad debt expense.

Environmental laws or regulations.

Passage of new environmental legislation or implementation of regulations that mandate reductions in greenhouse gas emissions or other similar restrictions could have a negative effect on the Company’s core operations. Natural gas is a clean and efficient energy source; however, the combustion of natural gas results in carbon related emissions. Such legislation could impose limitations on greenhouse gas emissions, require funding of new energy efficiency objectives, impose new operational requirements or lead to other additional costs to the Company. New regulations could result in a significant reduction in the use of coal as a fuel for electric power generation, potentially resulting in natural gas supply concerns and higher cost for natural gas. Legislation or regulations could limit the exploration and development of natural gas reserves, making the price of natural gas less competitive and less attractive as a fuel source for consumers, resulting in reduced deliveries and earnings.

Regulatory actions or failure to obtain timely rate relief could decrease future profitability.

The Company’s natural gas operations are regulated by the SCC. The SCC approves the rates that the Company charges its natural gas customers. If the SCC did not allow rates that provided for the timely recovery of costs or a reasonable rate of return on investment in natural gas distribution facilities, earnings could be negatively impacted. Issuance of debt and equity are also subject to SCC regulation and approval. Delays or lack of approvals could inhibit the ability to access capital markets and negatively impact liquidity or earnings.

Access to capital to maintain liquidity.

The Company relies on a variety of capital sources to operate its business and fund capital expenditures, including internally generated cash from operations, short-term borrowings under its line-of-credit, proceeds from stock issued under the Dividend Reinvestment and Stock Purchase Plan (“DRIP”) and other sources. Access to a line-of-credit is essential to provide seasonal funding of natural gas operations and provide capital budget bridge financing. Access to capital markets and other long-term funding sources is important to provide more predictable financing for capital outlays and funding of the investment in the LLC. The ability of the Company to maintain and renew its line-of-credit and to secure longer-term financing is critical to operations. Adverse market trends or deterioration in the financial condition of the Company could increase the cost of borrowing or limit the Company’s ability to secure adequate funding.

 

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Volatility in the price and availability of natural gas.

Natural gas purchases represent the single largest expense of the Company. Even with increasing demand from other areas including electric generation, natural gas prices are currently expected to remain stable in the near term, although there can be no guarantee to that effect. However, if restrictions on drilling for natural gas in the shale rock formations are imposed at either federal, state or local levels due to environmental or other concerns or other exploration and development restrictions on conventional drilling are enacted, the price of natural gas could escalate. The economic viability of the LLC could be significantly impacted by such restrictions. Furthermore, if demand for natural gas increases at a rate in excess of current expectations, natural gas prices could also face upward pressure. Increasing natural gas prices could make natural gas a less attractive energy source to the Company’s customers; thereby potentially resulting in declining sales as well as increases in bad debt expense.

Business activities are concentrated in a limited geographic region.

Changes in the Roanoke Valley’s economy, politics, regulations and weather patterns could negatively impact the existing customer base, leading to declining usage patterns and financial condition of customers, both of which could adversely affect earnings.

The cost of providing post-retirement benefits and related funding obligations may increase.

The costs of providing defined benefit pension and retiree medical plans are dependent on a number of factors such as the rates of return on plan assets, discount rates used in determining plan liabilities, the level of interest rates used to measure the required minimum funding levels of the plan, future government regulation, changes in life expectancy, and required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual results, as well as a significant decline in the value of investments that fund these plans, if not offset or mitigated by a decline in plan liabilities, could increase the expense of these plans and require significant additional funding of these plans. Such funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.

Weather conditions may cause revenues and earnings to vary from year to year.

The Company’s revenues and earnings are highly dependent upon weather conditions, specifically winter weather. The Company’s rate structure currently has a weather normalization adjustment factor that results in either a recovery or refund of revenues due to any variation from the 30-year average for heating degree-days. If the provision for the weather normalization adjustment were removed from its rate structure, the Company would be exposed to a much greater risk related to weather variability resulting in earnings volatility. A colder than normal winter could cause the Company to incur higher than normal operating and maintenance costs with no benefit of additional revenues to offset those costs as a result of the weather normalization adjustment.

Competition from other energy providers.

The Company competes with other energy providers in its service territory, including those that provide electricity, propane, coal, fuel oil and solar. A significant competitive factor is price. Higher natural gas costs or decreases in the price of other energy sources may enhance competition and encourage customers to convert their gas-fired equipment to systems that use alternative energy sources, thus lowering natural gas deliveries and earnings. Price considerations could also inhibit customer and revenue growth if builders and developers do not perceive natural gas to be a better value than other energy options and elect to install heating systems that use an energy source other than natural gas.

Failure to comply with debt covenant requirements could lead to adverse financial consequences that could affect the Company’s liquidity and ability to borrow funds.

The Company’s long-term debt obligations and bank line of credit contain financial covenants. Noncompliance with any of these covenants could result in an event of default which, if not cured or waived, could accelerate payment on outstanding debt obligations or cause prepayment penalties. In such an event, the Company may not be able to refinance or repay all of its indebtedness, pay dividends or have sufficient liquidity to meet operating and capital expenditure requirements. Any such acceleration would cause a material adverse change in our financial condition.

 

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Inability to complete necessary or desirable pipeline expansion or infrastructure development projects may delay or prevent the Company from adequately serving its customers or expanding its distribution system.

In order to serve new customers or expand service to existing customers, the Company needs to maintain, expand or upgrade its distribution, transmission and/or storage infrastructure, including new pipeline installation. Various factors may prevent or delay the completion of such projects or make them more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and an inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, the Company may not be able to adequately serve existing customers or support customer growth, which would negatively impact earnings.

 

Item 1B. Unresolved Staff Comments.

Not applicable.

 

Item 2. Properties.

Included in “Utility Plant” on the Company’s consolidated balance sheet are storage plant, transmission plant, distribution plant and general plant of Roanoke Gas as categorized by natural gas utilities. The Company has approximately 1,125 miles of transmission and distribution pipeline with transmission and distribution plant representing more than 85% of the total investment in plant. The transmission and distribution pipelines are located on or under public roads and highways or private property for which the Company has obtained the legal authorization and rights to operate.

Roanoke Gas owns and operates eight metering stations through which it measures and regulates the gas being delivered by its suppliers. These stations are located at various points throughout the Company’s distribution system.

Roanoke Gas also owns a liquefied natural gas storage facility located in Botetourt County that has the capacity to store up to 220,000 DTH of natural gas.

The Company’s executive, accounting and business offices, along with its maintenance and service departments, are located on Kimball Avenue in Roanoke, Virginia.

Although the Company considers its present properties adequate, management continues to evaluate the adequacy of its current facilities and intends to complete the replacement of its remaining cast iron and bare steel pipeline within the next two years.

 

Item 3. Legal Proceedings.

The Company was a defendant in two civil lawsuits associated with a November 2009 explosion and fire at a West Virginia residence. The first lawsuit was dismissed by order on March 31, 2015, and the second lawsuit was dismissed by order on April 27, 2015. The final resolution was consistent with management’s expectations as the settlement did not materially affect the Company’s financial position, results of operation, or liquidity.

The Company is not known to be a party to any other pending legal proceedings.

 

Item 4. Mine Safety Disclosures.

Not applicable.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Resources’ common stock is listed on the NASDAQ Global Market under the trading symbol RGCO. Payment of dividends is within the discretion of the Board of directors and will depend on, among other factors, earnings, capital requirements, and the operating and financial condition of the Company.

 

     Range of Bid Prices      Cash Dividends  
Year Ending September 30, 2015    High      Low      Declared  

First Quarter

   $ 22.45       $ 19.28       $ 0.1925   

Second Quarter

     25.67         20.20         0.1925   

Third Quarter

     22.99         19.78         0.1925   

Fourth Quarter

     21.96         19.95         0.1925   

Year Ending September 30, 2014

        

First Quarter

   $ 19.98       $ 18.10       $ 0.185   

Second Quarter

     20.06         18.46         0.185   

Third Quarter

     19.73         19.00         0.185   

Fourth Quarter

     20.51         19.17         0.185   

As of November 30, 2015, there were 1,209 holders of record of the Company’s common stock. This number does not include all beneficial owners of common stock who hold their shares in “street name.”

Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares the Company’s total shareholder return from September 30, 2010 through September 30, 2015 with the Dow Jones US Utility Index, a utility based index, and the Standard & Poor’s 500 Stock Index (S&P 500 Index), a broad market index.

The graph below reflects the value of a hypothetical investment of $100 made September 30, 2010 in the Company’s common stock and in each index as of September 30, 2015, assuming the reinvestment of all dividends. Historical stock price performance as reflected on the graph is not indicative of future price performance. The total value at the end of the five years was $172 for the Company’s common stock, $181 for the Dow Jones US Utilities Index and $187 for the S&P 500 Index.

 

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LOGO

A summary of the Company’s equity compensation plans follows as of September 30, 2015:

 

     (a)      (b)      (c)  

Plan category

   Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
     Weighted-average
exercise price of
outstanding
options, warrants
and rights
     Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
 

Equity compensation plans approved by security holders

     52,400       $ 19.83         128,134   

Equity compensation plans not approved by security holders

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total

     52,400       $ 19.83         128,134   
  

 

 

    

 

 

    

 

 

 

 

Item 6. Selected Financial Data.

 

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     Year Ending September 30,  
     2015      2014      2013      2012      2011  

Operating Revenues

   $ 68,189,607       $ 75,016,134       $ 63,205,666       $ 58,799,687       $ 70,798,871   

Gross Margin

     30,206,433         29,337,089         27,602,891         26,933,097         27,269,566   

Operating Income

     10,006,192         9,681,868         8,795,055         8,786,535         9,313,046   

Net Income

     5,094,415         4,708,440         4,262,052         4,296,745         4,653,473   

Basic Earnings Per Share

   $ 1.08       $ 1.00       $ 0.91       $ 0.92       $ 1.01   

Cash Dividends Declared Per Share

   $ 0.77       $ 0.74       $ 1.72       $ 0.70       $ 0.68   

Book Value Per Share

   $ 11.14       $ 11.02       $ 10.51       $ 10.85       $ 10.55   

Average Shares Outstanding

     4,728,210         4,715,478         4,698,727         4,647,439         4,592,713   

Total Assets

   $ 148,140,730       $ 139,127,641       $ 124,510,870       $ 129,735,019       $ 125,522,242   

Long-Term Debt (Less Current Portion)

   $ 30,500,000       $ 30,500,000       $ 13,000,000       $ 13,000,000       $ 13,000,000   

Stockholders’ Equity

     52,840,991         52,020,847         49,502,422         50,682,930         48,785,778   

Shares Outstanding at Sept. 30

     4,741,498         4,720,378         4,709,326         4,670,567         4,624,682   

 

Item 7. 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. 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 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” of this 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.

Overview

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 59,100 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities, through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Resources also provides certain unregulated services through Roanoke Gas and utility information system services through RGC Ventures of Virginia, Inc., which operates as The Utility Consultants and Application Resources. The Company also formed a new wholly-owned

 

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subsidiary, RGC Midstream, LLC (“Midstream”), which was created to invest in the Mountain Valley Pipeline (“MVP”) project. On October 1, 2015, Midstream executed the agreements to become a 1% member in the MVP project. More information is provided under the Equity Investment in Mountain Valley Pipeline section below. The unregulated operations represent less than 3% of revenues and margins of Resources.

The utility operations of Roanoke Gas are regulated by the Virginia State Corporation Commission (“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 prices for the transportation and delivery of natural gas to the Company’s distribution system and underground storage services. The Company is also subject to other regulations which are not necessarily industry specific.

The Company is committed to the safe and reliable delivery of natural gas to its customers. Since 1991, the Company has placed an emphasis on the modernization of its distribution system through the renewal and replacement of its cast iron and bare steel natural gas distribution pipelines. With recent regulatory actions placing a greater emphasis on pipeline safety, the Company continues to focus its efforts on completing its renewal and replacement program. Management anticipates replacing all remaining cast iron and bare steel pipe within the next two years and expects to continue its renewal program with plans to replace first generation pre-1973 plastic pipe.

The Company is also dedicated to the safeguarding of its information technology systems. These systems contain confidential customer, vendor and employee information as well as important financial data. There is risk associated with the unauthorized access of this information with a malicious intent to corrupt data, cause operational disruptions, or compromise information. Management believes it has taken reasonable security measures to protect these systems from cyber security attacks and other types of breaches; however, there can be no guarantee that a breach will not occur. In the event of a breach, the Company will execute its Security Incident Response Plan to assist with managing the incident. The Company also maintains cyber-insurance coverage to mitigate financial implications resulting from a breach of confidential information.

Over 97% of the Company’s 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 weather variations, 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 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 clause, 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 reduces the volatility in earnings due to the variability in temperatures during the heating season. The WNA is based on a weather measurement band around the most recent 30-year temperature average. The WNA provides the Company with a level of earnings protection when weather is warmer than normal and provides its customers with

 

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price protection when the weather is colder than normal. Prior to April 2014, the WNA provided a weather band of 3% above and below normal, whereby the Company would bill its customers for the lost margin (excluding gas costs) for the impact of weather that was more than 3% warmer than normal or refund customers the excess margin earned for weather that was more than 3% colder than normal. Effective with the WNA year that began April 2014, the 3% weather band was removed and the WNA is now based strictly on temperature variations from normal. For the fiscal year ended September 30, 2015, the Company recorded a $609,000 reduction in revenue for weather that was approximately 6.5% colder than normal. During the fiscal year ended September 30, 2014, the Company recorded a reduction in revenue of $563,000 to reflect the WNA adjustment for weather that was 8.8% colder than normal. If the WNA weather band had been 0% for the entire fiscal 2014 instead of 3% for the period October 1, 2013 through March 31, 2014, revenue would have been adjusted down by $814,000. No revenue adjustment for WNA was made for fiscal 2013 as the number of heating degree days fell within the 3% band then in effect.

The Company also has an approved rate structure in place that mitigates the impact of financing costs of 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. The carrying cost revenue (“ICC”) factor applied to average 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 revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and declining inventory balances, the Company recognizes less carrying cost revenue as financing costs are lower. As the commodity price for natural gas has declined by more than $1.00 a decatherm compared to the same period last year, the price of gas delivered into storage during the current year has declined by a similar amount. The result was a decline in the price of gas in storage to $3.38 per decatherm at September 30, 2015 compared to a price in storage of $4.71 and $4.08 at September 30, 2014 and 2013, respectively. However, the average dollar balance of gas in storage inventory actually increased over the prior fiscal year due to the higher-priced gas in storage at the beginning of fiscal 2015 combined with a greater level of withdrawals in fiscal 2014 due to the colder winter. Although the average balance of gas in storage during the current year was higher than the prior fiscal year, ICC revenues during fiscal 2015 declined by approximately $46,000 due to a reduction in the weighted-average cost of capital. The weighted-average cost of capital declined from last year due to the refinancing of the Company’s long-term debt in September 2014 combined with an increasing allocation of low cost short-term debt in the determination of the ICC rate. Based on the current prices of natural gas futures, the average dollar balance of gas in storage is expected to be much lower in the next fiscal year, resulting in lower ICC revenues in fiscal 2016.

Generally, as investment in natural gas inventory increases so does the level of borrowing under the Company’s line-of-credit. However, as the carrying cost factor used in determining carrying cost revenues is based on the Company’s weighted-average cost of capital, carrying cost revenues do not directly correspond with incremental short-term financing costs. Therefore, when inventory balances decline due to a reduction in commodity prices, net income will decline as carrying cost revenues decrease by a greater amount than short-term financing costs decrease. The inverse occurs when inventory costs increase.

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 made to include the additional investment and new non-gas rates are approved. The SAVE Plan and Rider provides the Company with the ability to recover costs related to these investments on a prospective basis rather than on a historical basis. The SAVE Plan provides a mechanism to recover the related depreciation and expenses and provide a return on rate base of the additional capital investments related to improving the Company’s infrastructure until such time 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 year and the level of capital investment continues to grow, SAVE Plan revenues have increased significantly. The Company recognized approximately $1,308,000, $292,000 and $169,000 in SAVE Plan revenues for years ended September 30, 2015, 2014 and 2013. SAVE 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. Additional information regarding the SAVE Rider is provided under the Regulatory Affairs section.

 

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The economic environment has a direct correlation with business and industrial production, customer growth and natural gas utilization. The local economy has lost some key business activities over the last year as some companies have either shut down or relocated all or portions of their operations elsewhere. In addition, a couple of the Company’s larger industrial customers have reduced natural gas consumption amid lower production activities. The impact of these relocations or the duration of these curtailments is unknown at this time. However, despite these losses, the local economy appears relatively stable and should continue to slowly improve absent a major economic setback, on either a local or national level.

Results of Operations

Fiscal Year 2015 Compared with Fiscal Year 2014

The table below reflects operating revenues, volume activity and heating degree-days.

Operating Revenues

 

Year Ended September 30,    2015      2014      Decrease      Percentage  

Gas Utilities

   $ 67,094,290       $ 73,865,487       $ (6,771,197      (9 )% 

Other

     1,095,317         1,150,647         (55,330      (5 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Operating Revenues

   $ 68,189,607       $ 75,016,134       $ (6,826,527      (9 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Delivered Volumes

 

Year Ended September 30,    2015      2014      Decrease      Percentage  

Regulated Natural Gas (DTH)

           

Residential and Commercial

     6,955,594         7,005,920         (50,326      (1 )% 

Transportation and Interruptible

     2,919,413         3,081,731         (162,318      (5 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Delivered Volumes

     9,875,007         10,087,651         (212,644      (2 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Heating Degree Days (Unofficial)

     4,253         4,351         (98      (2 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total gas utility operating revenues for the year ended September 30, 2015 decreased by 9% from the year ended September 30, 2014 primarily due to lower gas costs and a reduction in natural gas deliveries. The average commodity price of natural gas declined by 21% per decatherm sold. Delivered volumes declined due in part to weather, as reflected in the decline in residential and commercial volumes, and a reduction in industrial consumption. Residential and commercial deliveries tend to be more weather sensitive as reflected by a decline of 1% in volumes on 2% fewer heating degree days. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, decreased by 5%. Other revenues decreased by 5% as well.

Gross Margin

 

Year Ended September 30,    2015      2014      Increase /
(Decrease)
     Percentage  

Gas Utility

   $ 29,656,975       $ 28,774,213       $ 882,762         3

Other

     549,458         562,876         (13,418      (2 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Margin

   $ 30,206,433       $ 29,337,089       $ 869,344         3
  

 

 

    

 

 

    

 

 

    

 

 

 

Regulated natural gas margins from utility operations increased by 3% from fiscal 2014, primarily as a result of higher SAVE Plan revenues and customer base charges more than offsetting lower volumetric margins and ICC revenues. SAVE Plan revenues increased by $1,016,000. As the Company continues to invest in eligible SAVE Plan infrastructure, the associated SAVE Plan revenues will continue to increase. Customer base charges also increased due

 

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to modest customer growth. As discussed above, volumetric margin declined due to a reduction in total volumes delivered. Residential and commercial volumes declined primarily due to slightly warmer weather. Interruptible and transportation volumes declined due to the loss of a customer and decreased usage at two of the Company’s largest customers. The effect of the warmer weather was mitigated in part by the WNA mechanism. The prior year WNA mechanism provided for a weather band of 3% variance around normal during the winter heating season while the current heating season had a 0% weather band. Because the prior year had a 3% weather band in place for part of the year and weather was colder than normal, the Company was able to retain approximately $251,000 in excess margin realized on the 3% weather band, while the current year WNA with a 0% weather band required the adjustment of margin back to the level expected for normal weather.

Other margins, consisting of non-utility related services, decreased by $13,418 on comparable activity. The Utility Consultants, which ceased activity during fiscal 2015, contributed $17,000 to the non-utility related margin. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements which may result in fluctuations in revenues and margins.

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

 

     Twelve Months Ended September 30,      Increase  
     2015      2014      (Decrease)  

Customer Base Charge

   $ 12,240,580       $ 12,064,764       $ 175,816   

SAVE Plan

     1,307,795         291,946         1,015,849   

Volumetric

     15,757,907         15,990,704         (232,797

WNA

     (608,560      (563,187      (45,373

Carrying Cost

     833,291         879,381         (46,090

Other

     125,962         110,605         15,357   
  

 

 

    

 

 

    

 

 

 

Total

   $ 29,656,975       $ 28,774,213       $ 882,762   
  

 

 

    

 

 

    

 

 

 

Operations and Maintenance Expense - Operations and maintenance expenses increased by $103,497, or 1%, in fiscal 2015 compared with fiscal 2014 due to higher benefit costs and professional services and less overhead capitalization more than offsetting reductions in the level of bad debt expense, labor and contracted labor. Employee benefit expenses increased by $260,000 primarily due to higher medical, defined benefit pension plan (“pension plan”) and postretirement medical plan (“postretirement plan”) expense. The actuarially determined expenses for the pension and postretirement plans increased in fiscal 2015 due to a decline in the discount rate for valuing both plans’ liabilities at September 30, 2014. More information on these plans and the impact on the financial statements are provided under the Pension and Postretirement Benefits section of the Critical Accounting Policies and Estimates below and in Note 6 of the consolidated financial statements. Professional services increased by $77,000 primarily due to legal expenses associated with the new union contract, the formation of the Company’s new subsidiary and the due diligence work related to the investment in MVP. Additional information on the investment in MVP is provided under the Equity Investment in Mountain Valley Pipeline section below and in Note 12 of the consolidated financial statements. Total capitalized overheads declined by $106,000 because of delays in the production of liquified natural gas due to maintenance down time, lower capital expenditures and a reduction in the capitalization rate compared to the prior year. Bad debt expense decreased by $61,000 due to lower customer billings resulting from warmer weather and a lower commodity price of gas. Labor and contracted services costs declined by $133,000 due to timing of pipeline right-of-way clearing and prior year costs related to updating the Company’s corrosion control processes. The remaining decrease relates to a variety of areas including the level of facility and equipment maintenance, advertising and administrative costs.

General Taxes - General taxes increased $46,035, or 3%, primarily due to higher property taxes associated with increases in utility property.

Depreciation - Depreciation expense increased by $395,488, or 8%, corresponding to a similar increase in utility plant investment.

 

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Other Expense—Other expense, net, increased by $21,909, or 11%, primarily due to an increase in charitable requests related to specific campaigns.

Interest Expense—Total interest expense decreased by $314,582, or 17%, due to a lower interest rate on long-term debt. In September 2014, the Company refinanced its $28,000,000 in long-term debt, which had an average interest rate of 6.30% with $30,500,000 in new debt having a rate of 4.26%.

Income Taxes—Income tax expense increased by $231,022 on higher pre-tax earnings. The effective tax rate was 38.4% for both fiscal 2015 and 2014.

Net Income and Dividends—Net income for fiscal 2015 was $5,094,415 compared to $4,708,440 for fiscal 2014. Basic and diluted earnings per share were $1.08 in fiscal 2015 compared to $1.00 in fiscal 2014. Dividends declared per share of common stock were $0.77 in fiscal 2015 compared to $0.74 in fiscal 2014.

Fiscal Year 2014 Compared with Fiscal Year 2013

The table below reflects operating revenues, volume activity and heating degree-days.

Operating Revenues

 

                   Increase /         
Year Ended September 30,    2014      2013      (Decrease)      Percentage  

Gas Utilities

   $ 73,865,487       $ 62,024,174       $ 11,841,313         19

Other

     1,150,647         1,181,492         (30,845      (3 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Operating Revenues

     75,016,134         63,205,666         11,810,468         19
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Delivered Volumes

 

           
Year Ended September 30,    2014      2013      Increase      Percentage  

Regulated Natural Gas (DTH)

           

Residential and Commercial

     7,005,920         6,498,783         507,137         8

Transportation and Interruptible

     3,081,731         2,910,111         171,620         6
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Delivered Volumes

     10,087,651         9,408,894         678,757         7
  

 

 

    

 

 

    

 

 

    

 

 

 

Heating Degree Days (Unofficial)

     4,351         4,001         350         9
  

 

 

    

 

 

    

 

 

    

 

 

 

Total gas utility operating revenues for the year ended September 30, 2014 increased by 19% from the year ended September 30, 2013. The increase in gas revenues was primarily attributable to a combination of a 7% increase in total delivered natural gas volumes, a 30% per decatherm increase in the average commodity price of natural gas, implementation of a non-gas rate increase and higher SAVE Plan revenues. The increase in delivered volumes was driven by the colder winter heating season where total heating degree days increased by 9% over fiscal 2013 and were above the 30-year average by the same percentage. Transportation and interruptible volumes, which are primarily driven by production activities rather than weather, increased by 6%. Other revenues decreased by 3% due to the completion of a one-time project during the prior year more than offsetting increases in the level of certain other contract services during fiscal 2014.

 

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Gross Margin

 

Year Ended September 30,    2014      2013      Increase      Percentage  

Gas Utility

   $ 28,774,213       $ 27,108,112       $ 1,666,101         6

Other

     562,876         494,779         68,097         14
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Margin

   $ 29,337,089       $ 27,602,891       $ 1,734,198         6
  

 

 

    

 

 

    

 

 

    

 

 

 

Regulated natural gas margins from utility operations increased by 6% from fiscal 2013, primarily as a result of higher residential and commercial sales volumes, the implementation of a non-gas rate increase and the addition of the SAVE Plan rider. Residential and commercial volumes (which are strongly correlated to the weather) increased due to the much colder winter season. The higher margins generated by the increased residential and commercial volume were mostly offset by a net WNA refund of $563,000 recognized in fiscal 2014. The Company also implemented a non-gas rate increase effective November 1, 2013 and an increased SAVE Plan Rider beginning January 1, 2014. The non-gas rate increase was designed to provide approximately $887,000 in additional annual non-gas revenues. The implementation of the increased non-gas rates in November 2013 accounted for approximately $422,000 of the increase in customer base charges, a flat monthly fee billed to each natural gas customer, and $474,000 of the additional volumetric revenue. The SAVE Plan Rider provided an additional $123,000 in margin. ICC revenues continued to decline with a $58,000 reduction in fiscal 2014 compared to fiscal 2013 due to the larger storage withdrawals and lower ICC factor.

Other margins, consisting of non-utility related services, increased by $68,097 due to an increased level of activity under one of the contracted services. The service contracts that comprise most of the non-utility related activities are subject to annual or semi-annual renewal provisions and the potential exists that these contracts may not be renewed or extended by the customer. In addition, the level of activity under these contracts will fluctuate based on customer requirements.

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

 

     Twelve Months Ended September 30,      Increase  
     2014      2013      (Decrease)  

Customer Base Charge

   $ 12,064,764       $ 11,405,093       $ 659,671   

SAVE Plan

     291,946         168,747         123,199   

Volumetric

     15,990,704         14,497,351         1,493,353   

WNA

     (563,187      —           (563,187

Carrying Cost

     879,381         937,684         (58,303

Other

     110,605         99,237         11,368   
  

 

 

    

 

 

    

 

 

 

Total

   $ 28,774,213       $ 27,108,112       $ 1,666,101   
  

 

 

    

 

 

    

 

 

 

Operations and Maintenance Expense—Operations and maintenance expenses increased by $529,789, or 4%, in fiscal 2014 compared with fiscal 2013 primarily due to higher labor costs, contracted services, bad debt expense and corporate insurance expense more than offsetting significant reductions in employee benefit costs and greater capitalization of Company overheads on construction projects and LNG (liquefied natural gas) production. Labor costs and contracted services increased by $1,128,000 primarily due to a full year of increased operations staffing, timing of pipeline right-of-way clearing, a full year of costs related to an SCC mandated meter installation inspection and remediation program, expenses related to updating the Company’s corrosion control processes, benefit consulting services and network services support and training. Bad debt expense increased by approximately $64,000 related to much higher customer billings due to a colder winter heating season. Corporate property and liability insurance increased by $93,000 due to a combination of higher premiums and increased general liability coverage limits. These higher costs were partially offset by a $605,000 reduction in employee benefit expenses, specifically in the pension plan and postretirement plan. These actuarially determined expenses declined in fiscal 2014 due to a combination of a higher discount rate for valuing both plans’ liabilities at September 30, 2013 and strong investment performance of both plans’ assets. In addition, $339,000 of additional overheads was capitalized due to a significantly higher level of

 

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construction expenditures related to the Company’s renewal program and other projects. Total capital expenditures rose by more than $4.7 million over the prior year. The remaining increase of $188,000 relates to a variety of areas including additional facility and equipment maintenance and support costs, higher utility expenses and increased administrative costs related to the Company’s operations.

General Taxes—General taxes increased $79,640, or 5%, primarily due to higher property taxes associated with increases in utility property and greater payroll taxes related to increased operations staffing.

Depreciation—Depreciation expense increased by $237,956, or 5%, corresponding to the increase in utility plant investment partially offset by lower depreciation rates.

Other Expense—Other expense, net, increased by $146,770 primarily due to the absence of interest income related to the ANGD note which was paid off in fiscal 2013 combined with a greater level of corporate charitable giving and increased SCC pipeline assessments.

Interest Expense—Total interest expense remained virtually unchanged from fiscal 2013 as the Company benefited in September from lower interest expense due to its debt refinancing which offset the increased interest incurred under the line-of-credit.

Income Taxes—Income tax expense increased by $294,753 on higher pre-tax earnings. The effective tax rate for fiscal 2014 was 38.4% compared to 38.3% for 2013.

Net Income and Dividends—Net income for fiscal 2014 was $4,708,440 compared to $4,262,052 for fiscal 2013. Basic and diluted earnings per share were $1.00 in fiscal 2014 compared to $0.91 in fiscal 2013. Dividends declared per share of common stock were $0.74 in fiscal 2014 compared to $1.72 in fiscal 2013, which included the one-time special dividend of $1.00.

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 for the funding of its continuing construction program, the seasonal funding of its natural gas inventories and accounts receivables and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt, and to a lesser extent, capital raised through the Company’s stock plans.

Cash and cash equivalents increased by $135,477 in fiscal 2015 compared to decreases of $1,996,467 in fiscal 2014 and $6,063,647 in fiscal 2013. The following table summarizes the categories of sources and uses of cash:

Cash Flow Summary

 

     Year Ended September 30,  
     2015      2014      2013  

Provided by operating activities

   $ 16,760,827       $ 6,839,738       $ 10,037,070   

Used in investing activities

     (13,750,274      (14,698,570      (9,947,510

Provided by (used in) financing activities

     (2,875,076      5,862,365         (6,153,207
  

 

 

    

 

 

    

 

 

 

Increase (decrease) in cash and cash equivalents

   $ 135,477       $ (1,996,467    $ (6,063,647
  

 

 

    

 

 

    

 

 

 

Cash Flows Provided by Operating Activities:

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, all contribute to working capital levels and 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 the combination of increases in natural gas storage levels and rising customer receivable balances.

 

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Cash provided by operating activities was $16,761,000 in fiscal 2015, $6,840,000 in fiscal 2014 and $10,037,000 in fiscal 2013. Cash provided by operating activities increased by nearly $10,000,000 from last year primarily as a result of lower natural gas commodity prices and the extension of 50% bonus depreciation for tax purposes for calendar 2014. The gas cost component of the Company’s natural gas billing rates for the high volume winter period from January through March were derived based on natural gas futures pricing in early December 2014 when expectations were that prices would rise slightly during the period. Instead, the commodity price of gas declined by nearly $1.50 per decatherm from December 2014 until early February 2015, at which time the price leveled off. As a result, the Company was over-recovered on gas costs for billings rendered during this time period. The Company also benefited from the decline in natural gas prices as natural gas purchased for storage was at lower rates than in fiscal 2014. The Company purchases natural gas for storage purposes during the spring and summer months for use during the fall and winter heating season. As natural gas prices remained at lower levels during the spring and summer, the price of gas in storage declined from $4.71 per decatherm at September 30, 2014 to $3.38 at September 30, 2015, which resulted in an overall decline in storage inventory of $3,242,000. In addition, the extension of bonus depreciation to the end of calendar 2014 accounted for most of the increase in the deferred tax liability. Operating cash flow also increased due to higher net income and depreciation amounts. The cash windfall on the over-recovery of gas costs will be short-lived as the excess collected will be refunded to customers in 2016. In addition, deferred tax liabilities related to accelerated and bonus depreciation on the Company’s utility plant at September 30, 2015 will begin to reverse in 2016 or later, resulting in additional cash outflows for payment of the taxes. Conversely, during fiscal 2014 storage inventory balances increased by more than $1,000,000 and the Company went from an over-collected position to an under-collected position, resulting in a $1,208,000 use of operating cash.

Cash Flows Used in Investing Activities:

Investing activities primarily consist of expenditures under the Company’s construction program, which involves a combination of replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, making improvements to the LNG plant and expansion of its natural gas system to meet the demands of customer growth. The Company’s expenditures related to its pipeline renewal program and other system and infrastructure improvements and expansion have continued at elevated levels with total expenditures of $13,800,000 in fiscal 2015, $14,700,000 in fiscal 2014 and approximately $10,000,000 in fiscal 2013. The Company renewed 10 miles of bare steel and cast iron natural gas distribution main and replaced 594 services in fiscal 2015. This compares to 13.6 miles of main and 942 services in fiscal 2014 and 13 miles of main and 1,064 services in fiscal 2013. Total costs related to the renewal program continue to increase as the less complex and highly concentrated customer areas of the Company’s natural gas distribution system have been completed, leaving the more difficult sections to be done. Completion of the remaining pipeline replacement will more than likely be at a higher cost. The Company’s capital expenditures also included costs to extend mains and services to 609 new customers in fiscal 2015 compared to 673 in fiscal 2014 and 468 in fiscal 2013. In addition, the Company completed a significant main relocation and replacement of the compressor at the LNG plant in fiscal 2015.

RGC Resources is committed to the safe and reliable delivery of natural gas to its customers and, as a result, plans to commit the necessary resources to its pipeline renewal program with an expectation to replace all remaining cast iron and bare steel pipe within the next two years. As a reflection of this commitment, the Company’s capital budget for next year is currently estimated to be in excess of fiscal 2015 with the continuation of the pipeline replacement program and the replacement of two additional transfer stations. Depreciation provided approximately 38% of the current year’s capital expenditures compared to 33% for 2014 and 47% for 2013. Upon completion of the bare steel and cast iron pipe replacement, the Company plans to direct its efforts to replacing all pre-1973 plastic mains with polyethylene pipe. This project encompasses approximately 40 miles of natural gas main with a 2019 anticipated completion. The Company expects to increase its borrowing activity to meet the funding requirements of these plans.

Cash Flows Provided by (Used in) Financing Activities:

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As mentioned above, the Company uses its line-of-credit arrangement to fund seasonal working capital and provide temporary financing for capital projects. Cash flows used by financing activities were $2,875,000 for fiscal 2015 compared to cash provided by financing activities of $5,862,000 for fiscal 2014 and cash used in financing activities of $6,153,000 for fiscal 2013. After significant activity in the financing area in 2014,

 

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financing cash flow returned to a more normal pattern in fiscal 2015. In 2014, the Company refinanced $28,000,000 of its debt, including $2,238,000 in early termination fees on notes and interest rate swaps with $30,500,000 in unsecured 20-year term notes. The early termination fees were deferred as a regulatory asset and are being amortized over the term of the new notes as a component of interest expense. The $28,000,000 in retired debt had an average interest rate of 6.30% with an effective rate of 6.43%. The new debt has a stated interest rate of 4.26% and an effective rate of 4.67%. The nearly $315,000 reduction in interest expense in fiscal 2015 is entirely due to the refinancing. The Company’s utilization of its line-of-credit to fund both the Company’s seasonal working capital needs as well as bridge financing for its capital budget increased but not nearly to the extent expected due to the higher cash flows from operations. Dividends increased as the annualized dividend rate went from $0.74 per share to $0.77 per share in 2015. Fiscal 2013 included a special one-time dividend of $1.00 per share in addition to the regular quarterly dividend. The special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP Plan. The Company’s consolidated capitalization was 63.4% equity and 36.6% long-term debt at September 30, 2015. This compares to 63.0% equity and 37.0% long-term debt at September 30, 2014

Effective March 31, 2015, the Company entered into a new line-of-credit agreement. This new agreement maintains the same terms and rates as provided for under the expired agreement with an increase in the total borrowing limit. The interest rate is based on 30-day LIBOR plus 100 basis points and includes an availability fee of 15 basis points applied to the difference between the face amount of the note and the average outstanding balance during the period. The Company maintained multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs, with available limits ranging from $6,000,000 to $24,000,000 during the term of the agreement. The upper limit of the line-of-credit increased over prior years due to expected capital expenditure funding needs. The line-of-credit agreement will expire March 31, 2016. The Company anticipates being able to extend or replace the line-of-credit upon expiration; however, there is no guarantee that the line-of-credit will be extended or replaced under the same or equivalent terms currently in place.

In addition to the Company’s ongoing capital projects, Midstream has a commitment to invest approximately $35 million over the next three years under the agreement as a 1% member of Mountain Valley Pipeline, LLC. The Company plans to use a combination of debt and equity financing to meet this commitment.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements as defined in Regulation S-K, Item 303(a)(4)(ii).

Contractual Obligations and Commitments

The Company has incurred various contractual obligations and commitments in the normal course of business. As of September 30, 2015, the estimated recorded and unrecorded obligations are as follows:

 

     Less than 1      1-3      4-5      After         
Recorded contractual obligations:    year      Years      Years      5 Years      Total  

Long-Term Debt (1)

   $ —         $ —         $ —         $ 30,500,000       $ 30,500,000   

Short-Term Debt (2)

     9,340,997         —           —           —           9,340,997   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 9,340,997       $ —         $ —         $ 30,500,000       $ 39,840,997   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

  (1) See Note 4 to the consolidated financial statements.
  (2) See Note 3 to the consolidated financial statements.

 

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Unrecorded contractual obligations, not

reflected in consolidated balance sheets

in accordance with US GAAP:

   Less than 1
year
     1-3
Years
     4-5
Years
     After
5 Years
     Total  

Pipeline and Storage Capacity (3)

   $ 11,392,645       $ 17,787,400       $ 8,599,382       $ —         $ 37,779,427   

Gas Supply (4)

     —           —           —           —           —     

Interest on Short-Term Debt (5)

     24,457         —           —           —           24,457   

Interest on Long-Term Debt (6)

     1,299,300         2,598,600         2,598,600         18,192,200         24,688,700   

Pension Plan Funding (7)

     —           —           —           —           —     

Investment in MVP (8)

     5,300,000         25,000,000         4,700,000         —           35,000,000   

Other Obligations (9)

     114,501         34,598         2,340         27,380         178,819   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 18,130,903       $ 45,420,598       $ 15,900,322       $ 18,219,580       $ 97,671,403   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

  (3) Recoverable through the PGA process.
  (4) Volumetric obligation is for the purchase of contracted decatherms of natural gas at market prices in effect at the time of purchase. Unable to estimate related payment obligation until time of purchase. See Note 9 to the consolidated financial statements.
  (5) Accrued interest on line-of-credit balance at September 30, 2015, including minimum facility fee on unused line-of-credit. See Note 3 to the consolidated financial statements.
  (6) Semi-annual interest payment on 20-year $30.5 million note payable September 18, 2034. See Note 4 to the consolidated financial statements.
  (7) Estimated minimum funding assuming application of credit balances in plan to offset funding. Minimum funding requirements beyond five years is not available. See Note 6 to the consolidated financial statements.
  (8) Projected funding of the Company’s 1% interest in MVP as entered into on October 1, 2015.
  (9) Various lease, maintenance, equipment and service contracts.

Equity Investment in Mountain Valley Pipeline

On October 1, 2015, the Company, through its newly formed wholly-owned subsidiary, Midstream, entered into an agreement to become a 1% member in Mountain Valley Pipeline, LLC (the “LLC”), an investment in the Mountain Valley Pipeline project. The purpose of the LLC is to construct and operate a natural gas pipeline connecting an existing 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 with an expected decision in late 2016. Assuming a favorable response by FERC, the pipeline is expected to be in service 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, the Company will benefit from access to another source of natural gas to its distribution system. Currently, Roanoke Gas is served by two pipelines and a liquefied natural gas storage facility. Damage to or interruption in supply from any of these sources, especially during the winter heating season, could have a significant impact on the Company’s ability to serve its customers. A third pipeline would reduce the risk related to 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 $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, more significant cash draws will be required.

Regulatory Affairs

On June 30, 2015, the Company filed an application for modification of the SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan and Rider were 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

 

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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 amendments in 2013 and 2014 included additional projects related to the replacement of bare steel and cast iron natural gas pipe in addition to two other major projects and added the investment for the related meter and regulator installations located on customer premises. On September 25, 2015, the Company received approval for its most recent amendment to the SAVE Plan effective for calendar year 2016, which included an increase in the investment to complete replacement of the bare steel and cast iron natural gas pipe in addition to the replacement of first generation plastic pipe. The SCC also approved the inclusion of the replacement of two of the Company’s natural gas transfer stations and an increase in the allowed spending variance for projects under the SAVE Plan. The projects included under the SAVE Plan will enhance the safety and reliability of the Company’s gas distribution system and reduce greenhouse emissions. In addition, the recovery of the depreciation and related expenses on these projects through the SAVE Plan rider will allow the Company to forego a formal non-gas rate increase at this time.

The Company currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. Certificates of public convenience and necessity are issued by the SCC to provide service in the cities and counties in the Company’s service territory. These certificates are intended for perpetual duration subject to compliance and regulatory standards. Franchises are granted by the local cities and towns served by the Company and are generally granted for a defined period of time. The current franchises with the City of Roanoke, the City of Salem and the Town of Vinton will expire January 1, 2016. The Company is currently in negotiations to renew the franchises in each of these localities. Management anticipates that it will be able to renew all of its franchises.

On March 25, 2015, the Company filed an application for approval of a Certificate of Public Convenience and Necessity with the SCC to include the remaining uncertificated portions of Franklin County into its authorized natural gas service territory. On July 30, 2015, the Company filed a Motion to Stay Proceeding requesting the SCC stay the application request pending further progress in the review of the Mountain Valley Pipeline project by FERC and reconsider the application at a later date. The SCC granted the stay on July 31, 2015, which permitted the Company to continue its application request at a later date.

On June 4, 2014, the Company filed an application with the SCC requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term debt securities as part of its long-term financing plan, which included the refinancing of higher interest rate debt and funding for the Company’s pipeline replacement program and other infrastructure projects. On June 25, 2014, the SCC issued an order granting the approval of the Company’s request. The authority to issue long-term debt extends through September 30, 2019. In September 2014, the Company retired $28,000,000 in outstanding debt and replaced it with $30,500,000 in lower interest rate long-term debt. With significant capital expenditures planned over the next few years related to the SAVE Plan and other projects, the Company will have the flexibility to seek and manage the timing of long-term financing.

The Company’s provision for depreciation is computed principally based on composite rates determined by depreciation studies. These depreciation studies are required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. In June 2014, the Company filed an updated depreciation study with the SCC to update the previous study that was implemented in fiscal 2009. The SCC approved new rates in September 2014 which resulted in a small reduction in the overall composite depreciation rate from 3.35% in 2013 to 3.25% in fiscal 2014 and 2015. The new rates were implemented retroactive to October 1, 2013.

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 professional judgments. Actual results may differ significantly from these estimates and assumptions.

The Company considers an estimate to be critical if it is material to the financial statements and requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. The Company considers the following accounting policies and estimates to be critical.

 

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Regulatory accounting - The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities).

If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the Company would remove the applicable regulatory assets or liabilities from the balance sheet and include them in the consolidated statements of income and comprehensive income for the period in which the discontinuance occurred.

Revenue recognition - Regulated utility sales and transportation revenues are based upon rates approved by the SCC. The non-gas cost component of rates may not be changed without a formal rate application and corresponding authorization by the SCC in the form of a Commission order; however, the gas cost component of rates may be adjusted quarterly through the PGA mechanism. When the Company files a request for a non-gas rate increase, the SCC may allow the Company to place such rates into effect subject to refund pending a final order. Under these circumstances, the Company estimates the amount of increase it anticipates will be approved based on the best available information. The Company also bills customers through a SAVE Rider that provides a mechanism to recover on a prospective basis the costs associated with the Company’s expected investment related to the replacement of natural gas distribution pipe and other qualifying projects. As required under the provisions of FASB ASC No. 980, Regulated Operations, the Company recognizes billed revenue related to the SAVE projects to the extent such revenues have been earned under the provisions of the SAVE Plan.

The Company bills its regulated natural gas customers on a monthly cycle. The billing cycle for most customers does not coincide with the accounting periods used for financial reporting. The Company accrues estimated revenue for natural gas delivered to customers but not yet billed during the accounting period based on weather during the period and current and historical data. The financial statements include unbilled revenue of $1,001,418 and $1,071,128 as of September 30, 2015 and 2014, respectively.

Allowance for Doubtful Accounts - The Company evaluates the collectability of its accounts receivable balances based upon a variety of factors including loss history, level of delinquent account balances, collections on previously written off accounts and general economic conditions.

Pension and Postretirement Benefits - The Company offers a defined benefit pension plan (“pension plan”) and a postretirement medical and life insurance plan (“postretirement plan”) to eligible employees. The expenses and liabilities associated with these plans, as disclosed in Note 6 to the consolidated financial statements, are based on numerous assumptions and factors, including provisions of the plans, employee demographics, contributions made to the plan, return on plan assets and various actuarial calculations, assumptions and accounting requirements. In regard to the pension plan, specific factors include assumptions regarding the discount rate used in determining future benefit obligations, expected long-term rate of return on plan assets, compensation increases and life expectancies. Similarly, the postretirement medical plan also requires the estimation of many of the same factors as the pension plan in addition to assumptions regarding the rate of medical inflation and Medicare availability. Actual results may differ materially from the results expected from the actuarial assumptions due to changing economic conditions, differences in actual returns on plan assets, different rates of medical inflation, volatility in interest rates and changes in life expectancy. Such differences may result in a material impact on the amount of expense recorded in future periods or the value of the obligations on the balance sheet.

In selecting the discount rate to be used in determining the benefit liability, the Company utilized the Citigroup yield curves which incorporate the rates of return on high-quality, fixed-income investments that corresponded to the length and timing of benefit streams expected under both the pension plan and postretirement plan. The Company used a discount rate of 4.22% and 4.15% for valuing its pension plan liability and postretirement plan liability at September 30, 2015. This rate was unchanged for the pension plan and increased by only 0.05% from the prior year for the postretirement plan. The ongoing low interest rate environment has kept the discount rate depressed thereby keeping the liabilities at higher levels. Although the 30-year Treasury rate decreased from 3.21% to 2.87%, the Moody’s Aaa was nearly unchanged decreasing by only 0.05% which corresponds to the minimal change in the discount rates used by the benefit plans. As the discount rates remained at or near last year’s levels, the increase in each plan’s liability was

 

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driven in part to an additional year of accreated service. However, the most significant impact to the liabilities is attributed to the adoption of new mortality tables. On October 27, 2014, the Society of Actuaries released the final reports of the pension plan RP-2014 Mortality Tables and the Mortality Improvement Scale MP-2014. The new mortality tables, which were adopted by the Company for its current defined benefit plan valuations, extend the assumed life expectancy of participants in the plans and provide a better measure of defined benefit plan liabilities. The impact of the change in assumed mortality increased the Company’s pension liability by approximately 5% or nearly $1.3 million and the postretirement liability by approximately 7% or about $1 million, thereby increasing future expense.

Following better than expected returns in fiscal 2013 and 2014, the returns on the related pension and postretirement assets for fiscal 2015 fell short of the corresponding long-term rate of return assumptions. During fiscal 2015 fourth quarter, the equity markets experienced a greater than 10% market correction which was reflected in the plans’ asset balances at September 30, 2015. The Company took advantage of lower equity prices and contributed an additional $900,000 during the quarter, over and above the previously projected $800,000 annual contribution to the pension plan. The increased contributions served to mitigate the impact of the adoption of the RP-2014 Mortiality Tables and lower investment returns. As a result of the increase in the funded deficit, pension and postretirement medical plan expense will increase in fiscal 2016 due to an increase in the amortization of the actuarial loss. The following tables reflect the funded status of both plans at the corresponding fiscal year ends.

 

Funded status - September 30, 2015    Pension      Postretirement      Total  

Benefit obligation

   $ 27,167,621       $ 15,355,668       $ 42,523,289   

Fair value of assets

     21,394,399         10,443,629         31,838,028   
  

 

 

    

 

 

    

 

 

 

Funded status

   $ (5,773,222    $ (4,912,039    $ (10,685,261
  

 

 

    

 

 

    

 

 

 
Funded status - September 30, 2014    Pension      Postretirement      Total  

Benefit obligation

   $ 24,636,695       $ 14,983,169       $ 39,619,864   

Fair value of assets

     20,514,179         10,646,249         31,160,428   
  

 

 

    

 

 

    

 

 

 

Funded status

   $ (4,122,516    $ (4,336,920    $ (8,459,436
  

 

 

    

 

 

    

 

 

 

The economic environment makes it difficult to project interest rates and future investment returns. Current indications tend to support an increase in interest rates; however, any expectation or trend beyond an initial increase is indeterminable. If the economy improves, long-term interest rates could increase thereby reducing the benefit liabilities. However, increasing interest rates could have a negative effect on investment returns, especially in the fixed income allocation, and any benefit obtained from reduced benefit liabilities could be mitigated by less than expected returns on assets. Conversely, if the economy stagnates or declines, interest rates could remain at lower levels or even drop, leading to an increase in the benefit liabilities. The Company annually evaluates the returns on its targeted investment allocation model. The investment policy as of the measurement date in September reflected a targeted allocation of 60% equity and 40% fixed income on the pension plan and a targeted allocation of 50% equity and 50% fixed income for the postretirement plan. As a result of this evaluation, the Company set its expected long-term annual return on pension assets at 7.00% and postretirement assets at 4.89% (net of income taxes) for fiscal 2016. These rates are consistent with the expected long-term rates in place during fiscal 2015.

In August 2014, the Highway and Transportation Funding Act of 2014 (“HATFA”) was signed into law, which included a provision to extend the interest rate corridors introduced in 2012 under the Moving Ahead for Progress in the 21st Century Act (“MAP-21”). MAP-21 provided temporary funding relief for defined benefit pension plans. The requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and the Pension Protection Act of 2006 (PPA) subject defined benefit plans to minimum funding rules. As a result, when interest rates are low, pension plan liabilities increase thereby resulting in higher mandatory contributions to meet minimum funding obligations. MAP-21 provided funding relief by allowing pension plans to adjust the interest rates used in determining funding requirements so that they are within 10% of the average of interest rates for the 25-year period preceding the current year for funding calculations for 2013 to within 30% for funding periods beginning in 2016. HATFA extended the period of time that the 10% corridor instituted by MAP-21 may be used for funding calculations. Under HATFA, the

 

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10% corridor extends through plan years that begin in 2017 and phases out to a 30% corridor in 2021 and later. HATFA significantly increases the effective interest rates used in determining funding requirements and could result in a deterioration of the pension plan funded status resulting in much greater funding requirements in the future as well as higher PBGC (Pension Benefit Guaranty Corporation) premiums paid by sponsors of pension plans to protect participants in the event of default by the employer. Management estimates that, under the provisions of HATFA, the Company will have no minimum funding requirements next year. Although HATFA and MAP-21 allow the Company some short-term funding relief, management expects to continue its pension funding plan by contributing the greater of the minimum annual pension contribution requirement or its expense level for subsequent years. The Company currently expects to contribute approximately $500,000 to its pension plan and $500,000 to its postretirement plan in fiscal 2016. With pension expense expected to be approximately $837,000 in fiscal 2016, management is still following the funding strategy when considering the $900,000 in additional funding made in the fiscal fourth quarter of 2015. The Company will continue to evaluate its benefit plan funding levels in light of funding requirements and ongoing investment returns and make adjustments, as necessary, to avoid benefit restrictions.

The following schedule reflects the sensitivity of pension costs to changes in certain actuarial assumptions, assuming that the other components of the calculation remain constant.

 

Actuarial Assumptions

   Change in
Assumption
    Increase in
Pension Cost
     Increase in
Projected
Benefit
Obligation
 

Discount rate

     -0.25   $ 114,000       $ 1,132,000   

Rate of return on plan assets

     -0.25     53,000         N/A   

Rate of increase in compensation

     0.25     55,000         306,000   

The following schedule reflects the sensitivity of postretirement benefit costs from changes in certain actuarial assumptions, while the other components of the calculation remain constant.

 

Actuarial Assumptions

   Change in
Assumption
    Increase in
Postretirement
Benefit Cost
     Increase in
Accumulated
Postretirement
Benefit
Obligation
 

Discount rate

     -0.25   $ 35,000       $ 569,000   

Rate of return on plan assets

     -0.25     26,000         N/A   

Medical claim cost increase

     0.25     78,000         596,000   

Derivatives - The Company may hedge certain risks incurred in its operation through the use of derivative instruments. The Company applies the requirements of FASB ASC No. 815, Derivatives and Hedging, which requires the recognition of derivative instruments as assets or liabilities in the Company’s balance sheet at fair value. In most instances, fair value is based upon quoted futures prices for natural gas commodities and interest rate futures for interest rate swaps. Changes in the commodity and futures markets will impact the estimates of fair value in the future. Furthermore, the actual market value at the point of realization of the derivative may be significantly different from the values used in determining fair value in prior financial statements. The Company had no commodity or interest rate derivatives outstanding at September 30, 2015 and 2014.

 

Item 7A. 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. 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.

 

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Interest Rate Risk

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. As of September 30, 2015, the Company has $9,340,997 outstanding under its variable rate line-of-credit. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding during the year would have resulted in an increase in interest expense for the current year of approximately $64,700. The Company’s remaining debt is at a fixed rate.

Commodity Price Risk

The Company is also exposed to market risks through its natural gas operations associated with commodity prices. The Company’s hedging and derivatives policy, as authorized by the Company’s Board of Directors, allows management to enter into both physical and financial transactions for the purpose of managing the commodity risk of its business operations. The policy also specifies that the combination of all commodity hedging contracts for any 12-month period shall not exceed a total hedged volume of 90% of projected volumes. The policy specifically prohibits the use of derivatives for the purposes of speculation.

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 September 30, 2015, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had approximately 2,418,000 decatherms of gas in storage, including LNG, at an average price of $3.38 per decatherm compared to 2,424,000 decatherms at an average price of $4.71 per decatherm last year. The SCC currently allows for full recovery of prudent costs associated with natural gas purchases, and any additional costs or benefits associated with the settlement of the derivative contracts and other price hedging techniques are passed through to customers when realized through the regulated natural gas PGA mechanism.

 

Item 8. Financial Statements and Supplementary Data.

 

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 RGC Resources, Inc. and Subsidiaries

 Consolidated Financial Statements

 for the Years Ended September 30, 2015, 2014

 and 2013, and Report of Independent

 Registered Public Accounting Firm

 

29


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RGC RESOURCES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

 

     Page  

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     31   

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2015, 2014 and 2013:

  

Consolidated Balance Sheets

     32   

Consolidated Statements of Income

     34   

Consolidated Statements of Comprehensive Income

     35   

Consolidated Statements of Stockholders’ Equity

     36   

Consolidated Statements of Cash Flows

     37   

Notes to Consolidated Financial Statements

     38   

 

30


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LOGO

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

RGC Resources, Inc.

Roanoke, Virginia

We have audited the accompanying consolidated balance sheets of RGC Resources, Inc. and Subsidiaries (“the Company”) as of September 30, 2015 and 2014, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended September 30, 2015. RGC Resources, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RGC Resources, Inc. and Subsidiaries as of September 30, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), RGC Resources, Inc. and Subsidiaries’ internal control over financial reporting as of September 30, 2015, based on criteria established in Internal Control-Integrated Framework —1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 4, 2015 expressed an unqualified opinion.

 

LOGO
CERTIFIED PUBLIC ACCOUNTANTS

1715 Pratt Drive, Suite 2700

Blacksburg, Virginia

December 4, 2015

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2015 AND 2014

 

     2015     2014  

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 985,234      $ 849,757   

Accounts receivable, net

     3,196,573        3,730,173   

Materials and supplies

     968,108        893,672   

Gas in storage

     8,160,498        11,402,990   

Prepaid income taxes

     1,657,066        1,144,214   

Deferred income taxes

     2,293,536        1,704,320   

Under-recovery of gas costs

     —          180,831   

Other

     1,182,343        1,104,660   
  

 

 

   

 

 

 

Total current assets

     18,443,358        21,010,617   
  

 

 

   

 

 

 

UTILITY PROPERTY:

    

In service

     168,033,032        155,360,200   

Accumulated depreciation and amortization

     (53,307,079     (50,645,642
  

 

 

   

 

 

 

In service, net

     114,725,953        104,714,558   
  

 

 

   

 

 

 

Construction work in progress

     3,903,599        4,029,019   
  

 

 

   

 

 

 

Utility plant, net

     118,629,552        108,743,577   
  

 

 

   

 

 

 

OTHER ASSETS:

    

Regulatory assets

     10,923,243        9,273,389   

Other

     144,577        100,058   
  

 

 

   

 

 

 

Total other assets

     11,067,820        9,373,447   
  

 

 

   

 

 

 

TOTAL ASSETS

   $ 148,140,730      $ 139,127,641   
  

 

 

   

 

 

 

(Continued)

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

AS OF SEPTEMBER 30, 2015 AND 2014

 

     2015     2014  

LIABILITIES AND STOCKHOLDERS’ EQUITY

    

CURRENT LIABILITIES:

    

Borrowings under line-of-credit

   $ 9,340,997      $ 9,045,050   

Dividends payable

     912,995        873,326   

Accounts payable

     5,141,677        5,367,299   

Customer credit balances

     1,560,351        1,373,927   

Customer deposits

     1,579,441        1,492,150   

Accrued expenses

     2,766,097        2,200,882   

Over-recovery of gas costs

     1,901,426        —     
  

 

 

   

 

 

 

Total current liabilities

     23,202,984        20,352,634   
  

 

 

   

 

 

 

LONG-TERM DEBT

    

Principal amount

     30,500,000        30,500,000   

Less unamortized debt issuance costs

     (183,427     (193,081
  

 

 

   

 

 

 

Long-term debt net of unamortized debt issuance costs

     30,316,573        30,306,919   
  

 

 

   

 

 

 

DEFERRED CREDITS AND OTHER LIABILITIES:

    

Asset retirement obligations

     5,295,868        4,802,015   

Regulatory cost of retirement obligations

     8,885,486        8,575,147   

Benefit plan liabilities

     10,685,261        8,459,436   

Deferred income taxes

     16,913,567        14,610,643   
  

 

 

   

 

 

 

Total deferred credits and other liabilities

     41,780,182        36,447,241   
  

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 9)

    

CAPITALIZATION:

    

Stockholders’ Equity:

    

Common stock, $5 par value; authorized 10,000,000 shares; issued and outstanding 4,741,498 and 4,720,378 shares in 2015 and 2014, respectively

     23,707,490        23,601,890   

Preferred stock, no par; authorized 5,000,000 shares; no shares issued and outstanding in 2015 and 2014

     —          —     

Capital in excess of par value

     8,647,669        8,237,228   

Retained earnings

     22,772,377        21,321,055   

Accumulated other comprehensive loss

     (2,286,545     (1,139,326
  

 

 

   

 

 

 

Total stockholders’ equity

     52,840,991        52,020,847   
  

 

 

   

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 148,140,730      $ 139,127,641   
  

 

 

   

 

 

 

(Concluded)

See notes to consolidated financial statements.

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

 

     2015      2014      2013  

OPERATING REVENUES:

        

Gas utilities

   $ 67,094,290       $ 73,865,487       $ 62,024,174   

Other

     1,095,317         1,150,647         1,181,492   
  

 

 

    

 

 

    

 

 

 

Total operating revenues

     68,189,607         75,016,134         63,205,666   
  

 

 

    

 

 

    

 

 

 

COST OF SALES:

        

Gas utilities

     37,437,315         45,091,274         34,916,062   

Other

     545,859         587,771         686,713   
  

 

 

    

 

 

    

 

 

 

Total cost of sales

     37,983,174         45,679,045         35,602,775   
  

 

 

    

 

 

    

 

 

 

GROSS MARGIN

     30,206,433         29,337,089         27,602,891   
  

 

 

    

 

 

    

 

 

 

OTHER OPERATING EXPENSES:

        

Operations and maintenance

     13,486,885         13,383,388         12,853,599   

General taxes

     1,606,421         1,560,386         1,480,746   

Depreciation and amortization

     5,106,935         4,711,447         4,473,491   
  

 

 

    

 

 

    

 

 

 

Total other operating expenses

     20,200,241         19,655,221         18,807,836   
  

 

 

    

 

 

    

 

 

 

OPERATING INCOME

     10,006,192         9,681,868         8,795,055   

OTHER EXPENSE, net

     228,796         206,887         60,117   

INTEREST EXPENSE

     1,512,419         1,827,001         1,828,099   
  

 

 

    

 

 

    

 

 

 

INCOME BEFORE INCOME TAXES

     8,264,977         7,647,980         6,906,839   

INCOME TAX EXPENSE

     3,170,562         2,939,540         2,644,787   
  

 

 

    

 

 

    

 

 

 

NET INCOME

   $ 5,094,415       $ 4,708,440       $ 4,262,052   
  

 

 

    

 

 

    

 

 

 

EARNINGS PER COMMON SHARE:

        

Basic

   $ 1.08       $ 1.00       $ 0.91   

Diluted

   $ 1.08       $ 1.00       $ 0.91   

WEIGHTED AVERAGE SHARES OUTSTANDING:

        

Basic

     4,728,210         4,715,478         4,698,727   

Diluted

     4,731,676         4,716,282         4,698,766   

See notes to consolidated financial statements.

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

 

     2015     2014     2013  

NET INCOME

   $ 5,094,415      $ 4,708,440      $ 4,262,052   
  

 

 

   

 

 

   

 

 

 

Other comprehensive income, net of tax:

      

Interest rate swaps

     —          1,232,546        576,985   

Defined benefit plans

     (1,147,219     (220,638     1,221,866   
  

 

 

   

 

 

   

 

 

 

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX

     (1,147,219     1,011,908        1,798,851   
  

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME

   $ 3,947,196      $ 5,720,348      $ 6,060,903   
  

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements.

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

 

     Common
Stock
     Capital in
Excess of
Par Value
     Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
    Total
Stockholders’
Equity
 

Balance - September 30, 2012

   $ 23,352,835       $ 7,375,666       $ 23,904,514      $ (3,950,085   $ 50,682,930   

Net income

     —           —           4,262,052        —          4,262,052   

Other comprehensive income

     —           —           —          1,798,851        1,798,851   

Stock option grants

     —           84,840         —          —          84,840   

Cash dividends declared ($1.72 per share)

     —           —           (8,063,327     —          (8,063,327

Issuance of common stock (38,759 shares)

     193,795         543,281         —          —          737,076   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance - September 30, 2013

   $ 23,546,630       $ 8,003,787       $ 20,103,239      $ (2,151,234   $ 49,502,422   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Net income

     —           —           4,708,440        —          4,708,440   

Other comprehensive income

     —           —           —          1,011,908        1,011,908   

Stock option grants

     —           75,310         —          —          75,310   

Cash dividends declared ($0.74 per share)

     —           —           (3,490,624     —          (3,490,624

Issuance of common stock (11,052 shares)

     55,260         158,131         —          —          213,391   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance - September 30, 2014

   $ 23,601,890       $ 8,237,228       $ 21,321,055      $ (1,139,326   $ 52,020,847   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Net income

     —           —           5,094,415        —          5,094,415   

Other comprehensive loss

     —           —           —          (1,147,219     (1,147,219

Exercise of stock options (2,600 shares)

     13,000         36,366         —          —          49,366   

Stock option grants

     —           83,640         —          —          83,640   

Cash dividends declared ($0.77 per share)

     —           —           (3,643,093     —          (3,643,093

Issuance of common stock (18,520 shares)

     92,600         290,435         —          —          383,035   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance - September 30, 2015

   $ 23,707,490       $ 8,647,669       $ 22,772,377      $ (2,286,545   $ 52,840,991   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements.

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

 

     2015     2014     2013  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income

   $ 5,094,415      $ 4,708,440      $ 4,262,052   

Adjustments to reconcile net income to net cash provided by operations:

      

Depreciation and amortization

     5,219,893        4,838,062        4,656,716   

Cost of retirement of utility plant, net

     (406,731     (452,834     (502,587

Stock option grants

     83,640        75,310        84,840   

Deferred taxes and investment tax credits

     2,416,841        859,788        786,990   

Other noncash items, net

     105,815        38,073        39,186   

Changes in assets and liabilities which provided (used) cash:

      

Accounts receivable and customer deposits, net

     638,917        12,424        (374,682

Inventories and gas in storage

     3,168,056        (1,219,641     (997,378

Over/under recovery of gas costs

     2,082,257        (1,208,134     1,714,497   

Other assets

     (768,922     (306,744     1,106,590   

Accounts payable, customer credit balances and accrued expenses, net

     (873,354     (505,006     (739,154
  

 

 

   

 

 

   

 

 

 

Total adjustments

     11,666,412        2,131,298        5,775,018   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     16,760,827        6,839,738        10,037,070   
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Expenditures for utility property

     (13,780,356     (14,715,428     (9,977,433

Proceeds from disposal of utility property

     30,082        16,858        29,923   
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (13,750,274     (14,698,570     (9,947,510
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Proceeds on collection of notes

     —          —          1,142,770   

Borrowings under line-of-credit

     34,698,924        25,363,774        4,354,402   

Repayments under line-of-credit

     (34,402,977     (16,318,724     (4,354,402

Proceeds from issuance of unsecured notes

     —          30,500,000        —     

Retirement of note payable

     —          (15,000,000     —     

Retirement of long-term debt

     —          (13,000,000     —     

Early termination fees

     —          (2,237,961     —     

Debt issuance expenses

     —          (193,081     —     

Proceeds from issuance of stock

     432,401        213,391        737,076   

Cash dividends paid

     (3,603,424     (3,465,034     (8,033,053
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (2,875,076     5,862,365        (6,153,207
  

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     135,477        (1,996,467     (6,063,647

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

     849,757        2,846,224        8,909,871   
  

 

 

   

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF YEAR

   $ 985,234      $ 849,757      $ 2,846,224   
  

 

 

   

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

      

Cash paid during the year for:

      

Interest

   $ 1,002,462      $ 1,966,263      $ 1,803,528   

Income taxes

     1,266,573        2,387,000        622,076   

See notes to consolidated financial statements.

 

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RGC RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2015, 2014 AND 2013

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation—RGC Resources, Inc. is an energy services company engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”): Roanoke Gas Company (“Roanoke Gas”); Diversified Energy Company; RGC Ventures of Virginia, Inc., operating as Application Resources and The Utility Consultants; and RGC Midstream, LLC. Roanoke Gas is a natural gas utility, which distributes and sells natural gas to approximately 59,100 residential, commercial and industrial customers within its service areas in Roanoke, Virginia and the surrounding localities. The Company’s business is seasonal in nature and weather dependent as a majority of natural gas sales are for space heating during the winter season. Roanoke Gas is regulated by the Virginia State Corporation Commission (“SCC” or “Virginia Commission”). Application Resources provides information system services to software providers in the utility industry. The Utility Consultants, which provided regulatory consulting services to other utilities, ceased operations in 2015. RGC Midstream, LLC is a new wholly-owned subsidiary created in 2015 to invest in a pipeline project. More information is provided in Note 12. Diversified Energy Company is currently inactive.

The Company follows accounting and reporting standards set by the Financial Accounting Standards Board (“FASB”) and the Securities and Exchange Commission (“SEC”).

Resources has only one reportable segment as defined under FASB ASC No. 280 – Segment Reporting. All intercompany transactions have been eliminated in consolidation.

Rate Regulated Basis of Accounting—The Company’s regulated operations follow the accounting and reporting requirements of FASB ASC No. 980, Regulated Operations. The economic effects of regulation can result in a regulated company deferring costs that have been or are expected to be recovered from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this situation occurs, costs are deferred as assets in the consolidated balance sheet (regulatory assets) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (regulatory liabilities). In the event the provisions of FASB ASC No. 980 no longer apply to any or all regulatory assets or liabilities, the Company would write off such amounts and include them in the consolidated statements of income and comprehensive income in the period for which FASB ASC No. 980 no longer applied.

 

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Regulatory assets and liabilities included in the Company’s consolidated balance sheets as of September 30, 2015 and 2014 are as follows:

 

     September 30  
     2015      2014  

Regulatory Assets:

     

Current Assets:

     

Accounts receivable:

     

Accrued WNA revenues

   $ 229,281       $ 143,753   

Under-recovery of gas costs

     —           180,831   

Other:

     

Accrued pension and postretirement medical

     530,781         394,215   

Utility Property:

     

In service:

     

Other

     11,945         11,945   

Other Assets:

     

Regulatory assets:

     

Premium on early retirement of debt

     2,169,556         2,283,744   

Accrued pension and postretirement medical

     8,378,419         6,884,812   

Other

     375,268         104,833   
  

 

 

    

 

 

 

Total regulatory assets

   $ 11,695,250       $ 10,004,133   
  

 

 

    

 

 

 

Regulatory Liabilities:

     

Current Liabilities:

     

Over-recovery of gas costs

   $ 1,901,426       $ —     

Accrued expenses:

     

Over-recovery of SAVE Plan revenues

     153,365         187,203   

Deferred Credits and Other Liabilities:

     

Asset retirement obligations

     5,295,868         4,802,015   

Regulatory cost of retirement obligations

     8,885,486         8,575,147   
  

 

 

    

 

 

 

Total regulatory liabilities

   $ 16,236,145       $ 13,564,365   
  

 

 

    

 

 

 

As of September 30, 2015, the Company had regulatory assets in the amount of $9,513,749 on which the Company did not earn a return during the recovery period. These assets primarily pertain to the net funded position of the Company’s benefit plans related to its regulated operations. As such, the amortization period is not specifically defined.

Utility Plant and Depreciation—Utility plant is stated at original cost. The cost of additions to utility plant includes direct charges and overhead. The cost of depreciable property retired is charged to accumulated depreciation. The cost of asset removals, less salvage, is charged to “regulatory cost of retirement obligations” or “asset retirement obligations” as explained under Asset Retirement Obligations below. Maintenance, repairs, and minor renewals and betterments of property are charged to operations and maintenance.

Utility plant is comprised of the following major classes of assets:

 

     Years Ended September 30  
     2015      2014  

Distribution and transmission

   $ 143,172,628       $ 134,439,225   

LNG storage

     12,501,179         9,163,158   

General and miscellaneous

     12,359,225         11,757,817   
  

 

 

    

 

 

 

Total utility plant in service

   $ 168,033,032       $ 155,360,200   
  

 

 

    

 

 

 

 

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Provisions for depreciation are computed principally at composite straight-line rates as determined by depreciation studies required to be performed on the regulated utility assets of Roanoke Gas Company at least every five years. The Company completed its most recent depreciation study in June 2014. The composite weighted-average depreciation rates provided for under the new depreciation study were 3.25% for the fiscal years ended September 30, 2015 and 2014 compared to 3.35% for the fiscal year ended September 30, 2013 under the prior rates. For the year ended September 30, 2014, the implementation of the new depreciation rates reduced depreciation expense by $126,875 and increased net income by $78,713 and earnings per share by $0.02.

The composite rates are comprised of two components, one based on average service life and one based on cost of retirement. As a result, the Company accrues the estimated cost of retirement of long-lived assets through depreciation expense. Retirement costs are not a legal obligation but rather the result of cost-based regulation and are accounted for under the provisions of FASB ASC No. 980. Such amounts are classified as a regulatory liability.

The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These reviews have not identified any impairments which would have a material effect on the results of operations or financial condition.

Asset Retirement Obligations—FASB ASC No. 410, Asset Retirement and Environmental Obligations, requires entities to record the fair value of a liability for an asset retirement obligation when there exists a legal obligation for the retirement of the asset. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the underlying asset. In subsequent periods, the liability is accreted, and the capitalized cost is depreciated over the useful life of the underlying asset. The Company has recorded asset retirement obligations for its future legal obligations related to evacuating and capping its distribution mains and services upon retirement, although the timing of such retirements is uncertain.

The Company’s composite depreciation rates include a component to provide for the cost of retirement of assets. As a result, the Company accrues the estimated cost of retirement of its utility plant through depreciation expense and creates a corresponding regulatory liability. The costs of retirement considered in the development of the depreciation component include those costs associated with the legal liability. Therefore, the asset retirement obligation is reclassified from the regulatory cost of retirement obligation. If the legal obligations were to exceed the regulatory liability provided for in the depreciation rates, the Company would establish a regulatory asset for such difference with the anticipation of future recovery through rates charged to customers. In 2015, the Company increased its asset retirement obligation to reflect revisions to the estimated cash flows for asset retirements.

The following is a summary of the asset retirement obligation:

 

     Years Ended September 30  
     2015      2014  

Beginning balance

   $ 4,802,015       $ 4,525,355   

Liabilities incurred

     62,890         74,276   

Liabilities settled

     (162,072      (165,845

Accretion

     281,762         258,763   

Revisions to estimated cash flows

     311,273         109,466   
  

 

 

    

 

 

 

Ending balance

   $ 5,295,868       $ 4,802,015   
  

 

 

    

 

 

 

Cash, Cash Equivalents and Short-Term Investments—From time to time, the Company will have balances on deposit at banks in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). The Company has not experienced any losses on these accounts and does not consider these amounts to be at credit risk. As of September 30, 2015, the Company did not have any bank deposits in excess of the FDIC insurance limits. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Customer Receivables and Allowance for Doubtful Accounts—Accounts receivable include amounts billed to customers for natural gas sales and related services and gas sales occurring subsequent to normal billing cycles but before the end of the period. The Company provides an estimate for losses on these receivables by utilizing historical information, current account balances, account aging and current economic conditions. Customer accounts are charged off annually when deemed uncollectible or when turned over to a collection agency for action.

 

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A reconciliation of changes in the allowance for doubtful accounts is as follows:

 

     Years Ended September 30  
     2015      2014      2013  

Beginning balance

   $ 70,747       $ 68,539       $ 65,219   

Provision for doubtful accounts

     87,908         148,881         85,033   

Recoveries of accounts written off

     139,282         136,369         122,432   

Accounts written off

     (245,216      (283,042      (204,145
  

 

 

    

 

 

    

 

 

 

Ending balance

   $ 52,721       $ 70,747       $ 68,539   
  

 

 

    

 

 

    

 

 

 

Financing Receivables—Financing receivables represent a contractual right to receive money either on demand or on fixed or determinable dates and are recognized as assets on the entity’s balance sheet. Trade receivables are the Company’s one primary type of financing receivables, resulting from the sale of natural gas and other services to its customers. These receivable are short-term in nature with a provision for uncollectible balances included in the financial statements.

Inventories—Inventories, consisting of natural gas in storage and materials and supplies, are recorded at average cost. Injections into storage are priced at the purchase cost at the time of injection and withdrawals from storage are priced at the weighted average price in storage. Materials and supplies are removed from inventory at average cost.

Unbilled Revenues—The Company bills its natural gas customers on a monthly cycle; however, the billing cycle period for most customers does not coincide with the accounting periods used for financial reporting. As the Company recognizes revenue when gas is delivered, an accrual is made to estimate revenues for natural gas delivered to customers but not billed during the accounting period. The amounts of unbilled revenue receivable included in accounts receivable on the consolidated balance sheets at September 30, 2015 and 2014 were $1,001,418 and $1,071,128, respectively.

Income Taxes—Income taxes are accounted for using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. A valuation allowance against deferred tax assets is provided if it is more likely than not the deferred tax asset will not be realized. The Company and its subsidiaries file state and federal consolidated income tax returns.

Debt Expenses—Debt issuance expenses are amortized over the lives of the debt instruments.

Over/Under-Recovery of Natural Gas Costs—Pursuant to the provisions of the Company’s Purchased Gas Adjustment (“PGA”) clause, the SCC provides the Company with a method of passing along to its customers increases or decreases in natural gas costs incurred by its regulated operations, including gains and losses on natural gas derivative hedging instruments. 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 may either over-recover or under-recover its actual gas costs during the period. Any 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 deferral period, the balance of the net deferred charge or credit is amortized over an ensuing 12-month period as amounts are reflected in customer billings.

Fair Value—Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company determines fair value based on the following fair value hierarchy which prioritizes each input to the valuation methods 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.

 

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Level 3 – Unobservable inputs for the asset or liability where there is little, if any, market activity which require the Company to develop its own assumptions.

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). All fair value disclosures are categorized within one of the three categories in the hierarchy. See fair value disclosures below and in Notes 6 and 10.

Use of Estimates—The preparation of financial statements in conformity with Generally Accepted Accounting Principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent 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.

Excise and Sales Taxes—Certain excise and sales taxes imposed by the state and local governments in the Company’s service territory are collected by the Company from its customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the Company’s Consolidated Statements of Income.

Earnings Per Share—Basic earnings per share and diluted earnings per share are calculated by dividing net income by the weighted-average common shares outstanding during the period and the weighted-average common shares outstanding during the period plus dilutive potential common shares, respectively. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of basic and diluted earnings per share is presented below:

 

     Years Ended September 30  
     2015      2014      2013  

Net Income

   $ 5,094,415       $ 4,708,440       $ 4,262,052   
  

 

 

    

 

 

    

 

 

 

Weighted-average common shares

     4,728,210         4,715,478         4,698,727   

Effect of dilutive securities:

        

Options to purchase common stock

     3,466         804         39   
  

 

 

    

 

 

    

 

 

 

Diluted average common shares

     4,731,676         4,716,282         4,698,766   
  

 

 

    

 

 

    

 

 

 

Earnings Per Share of Common Stock:

        

Basic

   $ 1.08       $ 1.00       $ 0.91   

Diluted

   $ 1.08       $ 1.00       $ 0.91   

Business and Credit Concentrations—The primary business of the Company is the distribution of natural gas to residential, commercial and industrial customers in its service territories.

No sales to individual customers accounted for more than 5% of total revenue in any period or amounted to more than 5% of total accounts receivable.

Roanoke Gas currently holds the only franchises and certificates of public convenience and necessity to distribute natural gas in its service area. These franchises are effective through January 1, 2016. The Company’s current certificates of public convenience and necessity in Virginia are exclusive and are intended for perpetual duration.

Roanoke Gas is served directly by two primary pipelines that provide all of the natural gas supplied to the Company’s customers. Depending upon 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.

Derivative and Hedging Activities—FASB ASC No. 815, Derivatives and Hedging, requires the recognition of all derivative instruments as assets or liabilities in the Company’s balance sheet and measurement of those instruments at fair value.

The Company’s hedging and derivatives policy allows management to enter into derivatives for the purpose of managing commodity and financial market risks of its business operations. The Company’s hedging and derivatives policy specifically prohibits the use of derivatives for speculative purposes. The key market risks that RGC Resources, Inc. hedges against include the price of natural gas and the cost of borrowed funds.

The Company historically has entered into collars, swaps and caps for the purpose of hedging the price of natural gas in order to provide price stability during the winter months. The fair value of these instruments is recorded in the balance sheet with the offsetting entry to either under-recovery of gas costs or over-recovery of gas costs. Net income and other comprehensive income are not affected by the change in market value as any cost incurred or benefit received from these instruments is recoverable or refunded through the PGA as the SCC allows for full recovery of prudent costs associated with natural gas purchases. At September 30, 2015 and 2014, the Company had no outstanding derivative instruments for the purchase of natural gas.

 

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The Company also had two interest rate swaps that essentially converted its variable interest rate notes to fixed rate debt instruments. Both swaps were terminated in September 2014 as part of the Company’s debt refinancing. These swaps qualified as cash flow hedges with changes in fair value reported in other comprehensive income.

No derivative instruments were deemed to be ineffective for any period presented.

Other Comprehensive Income (Loss)—A summary of other comprehensive income is provided below:

 

     Before Tax
Amount
     Tax
(Expense)
or Benefit
     Net-of Tax
Amount
 

Year Ended September 30, 2015:

        

Defined benefit plans:

        

Net loss arising during period

   $ (1,910,573    $ 726,017       $ (1,184,556

Amortization of actuarial losses

     60,221         (22,884      37,337   
  

 

 

    

 

 

    

 

 

 

Other comprehensive loss

   $ (1,850,352    $ 703,133       $ (1,147,219
  

 

 

    

 

 

    

 

 

 

Year Ended September 30, 2014:

        

Interest rate swaps:

        

Unrealized losses

   $ (58,800    $ 22,321       $ (36,479

Transfer of realized losses to interest expense

     926,262         (351,609      574,653   

Transfer of realized losses to regulatory asset

     1,119,233         (424,861      694,372   
  

 

 

    

 

 

    

 

 

 

Net interest rate swaps

     1,986,695         (754,149      1,232,546   
  

 

 

    

 

 

    

 

 

 

Defined benefit plans:

        

Net loss arising during period

     (397,714      151,131         (246,583

Amortization of actuarial losses

     41,846         (15,901      25,945   
  

 

 

    

 

 

    

 

 

 

Net defined benefit plans

     (355,868      135,230         (220,638
  

 

 

    

 

 

    

 

 

 

Other comprehensive income

   $ 1,630,827       $ (618,919    $ 1,011,908   
  

 

 

    

 

 

    

 

 

 

Year Ended September 30, 2013:

        

Interest rate swaps:

        

Unrealized losses

   $ (20,479    $ 7,774       $ (12,705

Transfer of realized losses to interest expense

     950,501         (360,811      589,690   
  

 

 

    

 

 

    

 

 

 

Net interest rate swaps

     930,022         (353,037      576,985   
  

 

 

    

 

 

    

 

 

 

Defined benefit plans:

        

Net gain arising during period

     1,714,890         (651,659      1,063,231   

Amortization of actuarial losses

     219,890         (83,558      136,332   

Amortization of transition obligation

     35,972         (13,669      22,303   
  

 

 

    

 

 

    

 

 

 

Net defined benefit plans

     1,970,752         (748,886      1,221,866   
  

 

 

    

 

 

    

 

 

 

Other comprehensive income

   $ 2,900,774       $ (1,101,923    $ 1,798,851   
  

 

 

    

 

 

    

 

 

 

The amortization of actuarial losses and transition obligation is included as components of net periodic pension and postretirement benefit costs and is included in operations and maintenance expense.

 

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Composition of Accumulated Other Comprehensive Income (Loss)

 

     Interest Rate
Swaps
     Defined  Benefit
Plans
     Accumulated
Other
Comprehensive
Income (Loss)
 

Balance September 30, 2012

   $ (1,809,531    $ (2,140,554    $ (3,950,085

Other comprehensive income (loss)

     576,985         1,221,866         1,798,851   
  

 

 

    

 

 

    

 

 

 

Balance September 30, 2013

     (1,232,546      (918,688      (2,151,234

Other comprehensive income (loss)

     1,232,546         (220,638      1,011,908   
  

 

 

    

 

 

    

 

 

 

Balance September 30, 2014

     —           (1,139,326      (1,139,326

Other comprehensive income (loss)

     —           (1,147,219      (1,147,219
  

 

 

    

 

 

    

 

 

 

Balance September 30, 2015

   $ —         $ (2,286,545    $ (2,286,545
  

 

 

    

 

 

    

 

 

 

Change in Method of Accounting for Long-term Debt—During the fiscal year ended September 30, 2015, the Company adopted the provisions of ASU 2015-03 as described further under the Recently Adopted Accounting Standards section below. Under ASU 2015-03, the unamortized balance of debt issuance costs are reclassified from assets to liabilities and netted against the carrying value of long-term debt. The change had no impact on net income.

Management retrospectively applied the change. The carrying value of long-term debt and the reclassified debt issuance costs are presented separately on the Company’s Consolidated Balance Sheets and in Note 4 for the periods ended September 30, 2015 and 2014.

Recently Adopted Accounting Standards—In June 2011, the FASB issued guidance under FASB ASC No. 220—Comprehensive Income that defines the presentation of Comprehensive Income in the financial statements. According to the guidance, an entity may present a single continuous statement of comprehensive income or two separate statements—a statement of income and a statement of other comprehensive income that immediately follows the statement of income. In either presentation, the entity is required to present on the face of the financial statement the components of other comprehensive income including the reclassification adjustment for items that are reclassified from other comprehensive income to net income. In December 2011, the FASB issued additional guidance under FASB ASC No. 220 that deferred the effective date of earlier guidance with regard to the presentation of reclassifications of items out of accumulated other comprehensive income. All other provisions of the original guidance remain in effect. In February 2013, the FASB issued additional guidance regarding the reporting of amounts reclassified out of accumulated other comprehensive income. Under the new provisions, an entity must present the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income. The disclosures required under this guidance are provided above.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The Company previously recognized debt issuance costs in assets and amortized those costs over the term of the debt. This guidance is effective for the Company for the annual reporting period ending September 30, 2017 and interim periods within that annual period. Early application is permitted. The Company adopted the ASU during the current reporting period. The adoption of this ASU did not have an effect on the Company’s results of operations or cash flows; however, the unamortized balance of debt issuance costs were reclassified from assets to an offset against long-term debt. Certain deferred costs related to the early retirement of debt in 2014 are classified as regulatory assets and are not offset against debt. The changes required under this guidance are presented in Note 1, Note 4 and the Consolidated Balance Sheets.

Recently Issued Accounting Standards—In May 2014, the FASB issued guidance under FASB ASC No. 606—Revenue from Contracts with Customers 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 these 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 Accounting Standards Update (ASU) 2015-14 that deferred the effective date of this guidance by one year. Therefore, the new guidance is effective for the Company for the

 

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annual reporting period ended September 30, 2019 and interim periods within that annual period. Early application is not permitted. Management has not completed its evaluation of the new guidance; however, the Company does not currently expect it to have a material effect on its financial position, results of operations or cash flows.

Other accounting standards that have been issued or proposed by the FASB or other standard–setting bodies are not currently applicable to the Company or are not expected to have a significant impact on the Company’s financial position, results of operations and cash flows.

 

2. REGULATORY MATTERS

The SCC exercises regulatory authority over the natural gas operations of Roanoke Gas Company. Such regulation encompasses terms, conditions and rates to be charged to customers for natural gas service, safety standards, service extension, accounting and depreciation.

On September 25, 2015, the Company received approval of its application for a modification to the SAVE (Steps to Advance Virginia’s Energy) Plan and Rider. The original SAVE Plan filed in 2012 has been modified each year to incorporate certain changes and to include new projects that qualify for recovery under the Plan. The SAVE Rider provides 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.

On June 25, 2014, the SCC approved the Company’s application requesting approval to extend its authority to incur short-term indebtedness of up to $30,000,000 and to issue up to $60,000,000 in long-term securities. The short-term indebtedness authority allows the Company to continue to access its line-of-credit to provide seasonal funding of its working capital needs as well as provide temporary bridge financing for its capital expenditures. The authority to issue long-term securities allowed the Company to refinance its higher interest debt in September 2014 and provides the Company with the approval to secure longer term funding for its capital expenditures.

 

3. SHORT-TERM DEBT

The Company has available an unsecured line-of-credit with a bank which will expire March 31, 2016. The Company anticipates being able to extend or replace this line-of-credit upon expiration. The Company’s available unsecured line-of-credit varies during the year to accommodate its seasonal borrowing demands. Available limits under this agreement for the remaining term are as follows:

 

Effective

   Available
Line-of-Credit
 

September 30, 2015

   $ 24,000,000   

March 1, 2016

     17,000,000   

A summary of the line-of-credit follows:

 

     September 30  
     2015     2014     2013  

Line-of-credit at year-end

   $ 24,000,000      $ 15,000,000      $ 5,000,000   

Outstanding balance at year-end

     9,340,997        9,045,050        —     

Highest month-end balance outstanding

     17,366,052        9,045,050        1,414,955   

Average daily balance

     6,377,040        1,340,833        80,593   

Average rate of interest during year on outstanding balances

     1.17     1.16     1.21

Interest rate at year-end

     1.20     1.16     1.18

Interest rate on unused line-of-credit

     0.15     0.15     0.15

Associated with the line-of-credit is a credit agreement that contains various provisions including a financial ratio that requires the Company to maintain an interest coverage ratio of not less than 1.5 to 1.

 

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4. LONG-TERM DEBT

Long-term debt consists of the following:

 

     September 30  
     2015      2014  
     Principal      Unamortized
Debt Issuance
Costs
     Principal      Unamortized
Debt Issuance
Costs
 

Unsecured senior notes payable, at 4.26%, due on September 18, 2034

   $ 30,500,000       $ 183,427       $ 30,500,000       $ 193,081   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 30,500,000       $ 183,427       $ 30,500,000       $ 193,081   
  

 

 

    

 

 

    

 

 

    

 

 

 

Debt issuance costs are amortized over the life of the related debt. As of September 30, 2015 and 2014, the Company also had an unamortized loss on the early retirement of debt of $2,169,556 and $2,283,744, respectively, which has been deferred as a regulatory asset and is being amortized over a 20 year period.

The unsecured notes payable contain various provisions, including two financial covenants. First, total long-term debt, including current maturities, shall not exceed 65% of total capitalization. Second, the Company shall not allow priority indebtedness to exceed 15% of total assets.

The aggregate annual maturities of long-term debt for the next five years ending after September 30, 2015 are as follows:

 

Year Ending September 30

   Maturities  

2016

   $ —     

2017

     —     

2018

     —     

2019

     —     

2020

     —     

Thereafter

     30,500,000   
  

 

 

 

Total

   $ 30,500,000   
  

 

 

 

 

5. INCOME TAXES

The details of income tax expense are as follows:

 

     Years Ended September 30  
     2015      2014      2013  

Current income taxes:

        

Federal

   $ 379,180       $ 1,789,294       $ 1,404,450   

State

     374,541         290,458         453,347   
  

 

 

    

 

 

    

 

 

 

Total current income taxes

     753,721         2,079,752         1,857,797   
  

 

 

    

 

 

    

 

 

 

Deferred income taxes:

        

Federal

     2,289,729         687,417         829,080   

State

     127,112         175,464         (33,051
  

 

 

    

 

 

    

 

 

 

Total deferred income taxes

     2,416,841         862,881         796,029   
  

 

 

    

 

 

    

 

 

 

Amortization of investment tax credits

             (3,093      (9,039
  

 

 

    

 

 

    

 

 

 

Total income tax expense

   $ 3,170,562       $ 2,939,540       $ 2,644,787   
  

 

 

    

 

 

    

 

 

 

 

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Income tax expense for the years ended September 30, 2015, 2014 and 2013 differed from amounts computed by applying the U.S. Federal income tax rate of 34% to earnings before income taxes due to the following:

 

     Years Ended September 30  
     2015      2014      2013  

Income before income taxes

   $ 8,264,977       $ 7,647,980       $ 6,906,839   

Income tax expense computed at the federal statutory rate

   $ 2,810,092       $ 2,600,313       $ 2,348,325   

State income taxes, net of federal income tax benefit

     331,091         307,509         277,395   

Amortization of investment tax credits

     —           (3,093      (9,039

Other, net

     29,379         34,811         28,106   
  

 

 

    

 

 

    

 

 

 

Total income tax expense

   $ 3,170,562       $ 2,939,540       $ 2,644,787   
  

 

 

    

 

 

    

 

 

 

The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are as follows:

 

     September 30  
     2015      2014  

Deferred tax assets:

     

Allowance for uncollectibles

   $ 20,012       $ 26,855   

Accrued pension and postretirement medical benefits

     2,502,774         2,077,409   

Accrued vacation

     249,837         230,842   

Over-recovery of gas costs

     721,782         —     

Costs of gas held in storage

     930,524         973,651   

Accrued gas costs

     —           36,305   

Deferred compensation

     651,336         579,451   

Other

     265,951         295,654   
  

 

 

    

 

 

 

Total gross deferred tax assets

     5,342,216         4,220,167   
  

 

 

    

 

 

 

Deferred tax liabilities:

     

Utility plant

     19,804,862         17,057,847   

Under-recovery of gas costs

     —           68,643   

Accrued gas costs

     157,385         —     
  

 

 

    

 

 

 

Total gross deferred tax liabilities

     19,962,247         17,126,490   
  

 

 

    

 

 

 

Net deferred tax liability

   $ 14,620,031       $ 12,906,323   
  

 

 

    

 

 

 

Deferred Income Tax - Balance Sheet

     
     September 30  
     2015      2014  

Deferred income taxes (net current assets)

   $ 2,293,536       $ 1,704,320   

Deferred income taxes (net non-current liabilities)

     16,913,567         14,610,643   
  

 

 

    

 

 

 

Net deferred tax liability

   $ 14,620,031       $ 12,906,323   
  

 

 

    

 

 

 

Current federal tax expense for fiscal 2015 reflected the effect of 50% bonus depreciation for the entire calendar year of 2014, which included nine months of the prior fiscal year. The extension of bonus depreciation for 2014 was signed into law subsequent to the issuance of the Company’s financial statements for the year ended September 30, 2014. As a result, $1,442,211 of deferred taxes that related to the prior year were reflected in the current year tax provision, thereby reducing the current tax expense by the same amount. Total income tax expense was not impacted by the classification change between current and deferred income taxes.

 

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FASB ASC No. 740 - Income Taxes provides for the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recognized in the financial statements. The Company has evaluated its tax positions and accordingly has not identified any significant uncertain tax positions. The Company’s policy is to classify interest associated with uncertain tax positions as interest expense in the financial statements. Penalties are classified under other expense.

The Company files a consolidated federal income tax return and state income tax returns in Virginia and West Virginia. The federal returns and the state returns for both Virginia and West Virginia for the tax years ended prior to September 30, 2012 are no longer subject to examination.

 

6. EMPLOYEE BENEFIT PLANS

The Company sponsors both a noncontributory defined benefit pension plan and a postretirement benefit plan (“Plans”). The defined benefit pension plan covers substantially all employees and benefits fully vest after 5 years of credited service. Benefits paid to retirees are based on age at retirement, years of service and average compensation. The postretirement benefit plan provides certain healthcare, supplemental retirement and life insurance benefits to retired employees who meet specific age and service requirements. Employees hired prior to January 1, 2000 are eligible to participate in the postretirement benefit plan. Employees must have a minimum of 10 years of service and retire after attaining the age of 55 in order to vest in the postretirement plan. Retiree contributions to the plan are based on the number of years of service to the Company as determined under the defined benefit plan.

Employers who sponsor defined benefit plans must recognize the funded status of defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and recognize changes in that funded status in the year in which the changes occur through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation, and for other postretirement plans, the benefit obligation is the accumulated benefit obligation. The Company established a regulatory asset for the portion of the obligation expected to be recovered in rates in future periods. The regulatory asset is adjusted for the amortization of the transition obligation and recognition of actuarial gains and losses. The portion of the obligation attributable to the unregulated operations of the holding company is recognized in other comprehensive income.

 

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The following tables set forth the benefit obligation, fair value of plan assets, the funded status of the benefit plans, amounts recognized in the Company’s financial statements and the assumptions used.

 

     Pension Plan      Postretirement Plan  
     2015      2014      2015      2014  

Accumulated benefit obligation

   $ 22,853,206       $ 20,697,734       $ 15,355,668       $ 14,983,169   
  

 

 

    

 

 

    

 

 

    

 

 

 

Change in benefit obligation:

           

Benefit obligation at beginning of year

   $ 24,636,695       $ 21,468,769       $ 14,983,169       $ 13,028,628   

Service cost

     654,782         553,291         167,580         168,634   

Interest cost

     1,025,908         1,020,302         600,096         602,684   

Actuarial loss

     1,487,278         2,199,697         70,196         1,673,552   

Benefit payments, net of retiree contributions

     (637,042      (605,364      (465,373      (490,329
  

 

 

    

 

 

    

 

 

    

 

 

 

Benefit obligation at end of year

   $ 27,167,621       $ 24,636,695       $ 15,355,668       $ 14,983,169   
  

 

 

    

 

 

    

 

 

    

 

 

 

Change in fair value of plan assets:

           

Fair value of plan assets at beginning of year

   $ 20,514,179       $ 18,801,262       $ 10,646,249       $ 10,114,062   

Actual return on plan assets, net of taxes

     (182,738      1,750,033         (237,247      522,516   

Employer contributions

     1,700,000         568,248         500,000         500,000   

Benefit payments, net of retiree contributions

     (637,042      (605,364      (465,373      (490,329
  

 

 

    

 

 

    

 

 

    

 

 

 

Fair value of plan assets at end of year

   $ 21,394,399       $ 20,514,179       $ 10,443,629       $ 10,646,249   
  

 

 

    

 

 

    

 

 

    

 

 

 

Funded status

   $ (5,773,222    $ (4,122,516    $ (4,912,039    $ (4,336,920
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts recognized in the balance sheets consist of:

           

Noncurrent liabilities

   $ (5,773,222    $ (4,122,516    $ (4,912,039    $ (4,336,920
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts recognized in accumulated other comprehensive loss:

           

Transition obligation, net of tax

   $ —         $ —         $ —         $ —     

Net actuarial loss, net of tax

     1,694,924         616,352         591,621         522,974   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total amounts included in other comprehensive loss, net of tax

   $ 1,694,924       $ 616,352       $ 591,621       $ 522,974   
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts deferred to a regulatory asset:

           

Transition obligation

   $ —         $ —         $ —         $ —     

Net actuarial loss

     5,280,756         4,166,900         3,628,448         3,112,127   
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts recognized as regulatory assets

   $ 5,280,756       $ 4,166,900       $ 3,628,448       $ 3,112,127   
  

 

 

    

 

 

    

 

 

    

 

 

 

Effective with the valuation of the September 30, 2015 defined benefit obligations, the Company adopted the new RP-2014 Mortality Tables as issued by the Society of Actuaries in late 2014. The adoption of the new tables, which reflected an increase in assumed life expectancy, increased the September 30, 2015 pension liability by an estimated $1,300,000 and the postretirement liability by an estimated $1,000,000.

The Company expects that approximately $221,000 before tax, of accumulated other comprehensive loss will be recognized as a portion of net periodic benefit costs in fiscal 2016 and approximately $531,000 of amounts deferred as regulatory assets will be amortized and recognized in net periodic benefit costs in fiscal 2016.

The Company amortized the unrecognized transition obligation over 20 years ending in June 2013.

 

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The following table details the actuarial assumptions used in determining the projected benefit obligations and net benefit cost of the pension and the accumulated benefit obligations and net benefit cost of the postretirement plan for 2015, 2014 and 2013.

 

     Pension Plan     Postretirement Plan  
     2015     2014     2013     2015     2014     2013  

Assumptions used to determine benefit obligations:

            

Discount rate

     4.22     4.22     4.82     4.15     4.10     4.73

Expected rate of compensation increase

     4.00     4.00     4.00     N/A        N/A        N/A   

Assumptions used to determine benefit costs:

            

Discount rate

     4.22     4.82     4.06     4.10     4.73     3.95

Expected long-term rate of return on plan assets

     7.00     7.00     7.25     4.90     4.92     5.11

Expected rate of compensation increase

     4.00     4.00     4.00     N/A        N/A        N/A   

To develop the expected long-term rate of return on assets assumption, the Company, with input from the plans’ actuaries and investment advisors, considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of each plan’s portfolio.

Components of net periodic benefit cost are as follows:

 

     Pension Plan      Postretirement Plan  
     2015      2014      2013      2015      2014      2013  

Service cost

   $ 654,782       $ 553,291       $ 634,892       $ 167,580       $ 168,634       $ 213,131   

Interest cost

     1,025,908         1,020,302         946,247         600,096         602,684         531,845   

Expected return on plan assets

     (1,440,846      (1,312,354      (1,184,787      (516,656      (496,476      (452,383

Amortization of unrecognized transition obligation

     —           —           —           —           —           141,671   

Recognized loss

     257,378         136,394         578,263         197,058         89,515         241,747   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net periodic benefit cost

   $ 497,222       $ 397,633       $ 974,615       $ 448,078       $ 364,357       $ 676,011   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The assumed health care cost trend rates used in measuring the accumulated benefit obligation for the postretirement medical plan as of September 30, 2015, 2014 and 2013 are presented below:

 

     Pre 65     Post 65  
     2015     2014     2013     2015     2014     2013  

Health care cost trend rate assumed for next year

     8.00     8.50     9.00     5.00     5.00     5.00

Rate to which the cost trend is assumed to decline (the ultimate trend rate)

     5.00     5.00     5.00     5.00     5.00     5.00

Year that the rate reaches the ultimate trend rate

     2021        2021        2021        2015        2014        2013   

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects:

 

     1% Increase      1% Decrease  

Effect on total service and interest cost components

   $ 137,000       $ (109,000

Effect on accumulated postretirement benefit obligation

     2,383,000         (1,938,000

The primary objectives of the Plan’s investment policy are to maintain investment portfolios that diversify risk through prudent asset allocation parameters, achieve asset returns that meet or exceed the plans’ actuarial assumptions, achieve asset returns that are competitive with like institutions employing similar investment strategies and meet expected future benefits in both the short-term and long-term. The investment policy provides for a range of investment allocations to allow for flexibility in responding to market conditions. The investment policy is periodically reviewed by the Company and a third-party fiduciary for investment matters.

 

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The Company’s target and actual asset allocation in the pension and postretirement benefit plans as of September 30, 2015 and 2014 were:

 

     Pension Plan     Postretirement
Plan
 
     Target     2015     2014     Target     2015     2014  

Asset category:

            

Equity securities

     60     64     60     50     52     55

Debt securities

     40     35     39     50     47     44

Cash

     —       1     1     —       1     1

Other

     —       —       —       —       —       —  

The assets of the plans are invested in mutual funds. The Company uses the fair value hierarchy described in Note 1 to classify these assets. The mutual funds are included under Level 2 in the fair value hierarchy as their fair values are determined based on individual prices for each security that comprises the mutual funds. Most all of the individual investments are determined based on quoted market prices for each security; however, certain fixed income securities and other investments are not actively traded and are valued based on similar investments. The following table contains the fair value classifications of the benefit plan assets:

 

            Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2015
 
     Fair Value      Level 1      Level 2      Level 3  

Asset Class:

           

Cash

   $ 106,502       $ 106,502       $ —         $ —     

Common and Collective Trust and

           

Pooled Funds:

           

Bonds

           

Domestic Fixed Income

     3,996,246         —           3,996,246         —     

Equities

           

Domestic Large Cap Growth

     3,150,561         —           3,150,561         —     

Domestic Large Cap Value

     4,183,172         —           4,183,172         —     

Domestic Small/Mid Cap Core

     1,937,613         —           1,937,613         —     

Foreign Large Cap Value

     1,873,313         —           1,873,313         —     

Mutual Funds:

           

Bonds

           

Domestic Fixed Income

     3,313,331         —           3,313,331         —     

Foreign Fixed Income

     213,118         —           213,118         —     

Equities

           

Domestic Large Cap Growth

     1,030,957         —           1,030,957         —     

Foreign Large Cap Value

     653,276         —           653,276         —     

Foreign Large Cap Core

     936,310         —           936,310         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 21,394,399       $      106,502       $ 21,287,897       $             —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents
            Defined Benefit Pension Plan
Fair Value Measurements - September 30, 2014
 
     Fair Value      Level 1      Level 2      Level 3  

Asset Class:

           

Cash

   $ 182,644       $ 182,644       $ —         $ —     

Common and Collective Trust and Pooled Funds:

           

Bonds

           

Domestic Fixed Income

     1,455,153         —           1,455,153         —     

Equities

           

Domestic Large Cap Growth

     2,079,566         —           2,079,566         —     

Domestic Large Cap Value

     3,295,144         —           3,295,144         —     

Domestic Small/Mid Cap Core

     1,850,340         —           1,850,340         —     

Foreign Large Cap Value

     1,641,619         —           1,641,619         —     

Mutual Funds:

           

Bonds

           

Domestic Fixed Income

     6,289,437         —           6,289,437         —     

Foreign Fixed Income

     204,747         —           204,747         —     

Equities

           

Domestic Large Cap Growth

     2,088,528         —           2,088,528         —     

Foreign Large Cap Value

     608,787         —           608,787         —     

Foreign Large Cap Core

     818,214         —           818,214         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 20,514,179       $      182,644       $ 20,331,535       $           —     
  

 

 

    

 

 

    

 

 

    

 

 

 
            Postretirement Benefit Plan
Fair Value Measurements - September 30, 2015
 
     Fair Value      Level 1      Level 2      Level 3  

Asset Class:

           

Cash

   $ 58,749