RGC Resources - 10-Q quarterly report FY2013 Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-26591

(540) 777-4427

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

____________________________________________________ 

Indicate by check mark whether the registrant 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.

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

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

SUPPLEMENTAL INFORMATION - NON-CASH TRANSACTION:

The Company’s $15,000,000 note due March 31, 2013 was refinanced with the issuance of a $15,000,000 one-year term note dated March 31, 2013.

See notes to condensed consolidated financial statements.

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

RGC Resources, Inc. is an energy services company primarily engaged in the sale and distribution of natural gas. The consolidated financial statements include the accounts of RGC Resources, Inc. and its wholly owned subsidiaries (“Resources” or the “Company”); Roanoke Gas Company; Diversified Energy Company; and RGC Ventures of Virginia, Inc.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly RGC Resources, Inc.’s financial position as of June 30, 2013 and the results of its operations and comprehensive income for the three months and nine months ended June 30, 2013 and 2012 and its cash flows for the nine months ended June 30, 2013 and 2012. The results of operations for the three months and nine months ended June 30, 2013 are not indicative of the results to be expected for the fiscal year ending September 30, 2013 as quarterly earnings are affected by the highly seasonal nature of the business and weather conditions generally result in greater earnings during the winter months.

The unaudited condensed consolidated interim financial statements and condensed notes are presented as permitted under the rules and regulations of the Securities and Exchange Commission. Pursuant to those rules, certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures made are adequate to make the information not misleading. Therefore, the condensed consolidated financial statements and condensed notes should be read in conjunction with the financial statements and notes contained in the Company’s Form 10-K. The September 30, 2012 balance sheet was included in the Company’s audited financial statements on Form 10-K.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements in Form 10-K for the year ended September 30, 2012. Newly adopted and newly issued accounting standards are discussed below.

Recently Issued Accounting Standards

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 in Note 6 below.

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

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

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

 

The table in Note 6 reflects the effect on income and other comprehensive income of the Company’s cash flow hedges.

 

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

 

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

 

Composition of Other Accumulated Comprehensive Income (Loss)

Due to the nature of the natural gas distribution business, the Company has entered into agreements with both suppliers and pipelines for natural gas commodity purchases, storage capacity and pipeline delivery capacity. The Company obtains most of its regulated natural gas supply from an asset manager. The Company uses an asset manager to assist in optimizing the use of its transportation, storage rights, and gas supply in order to provide a secure and reliable source of natural gas to its customers. The Company also has storage and pipeline capacity contracts to store and deliver natural gas to the Company’s distribution system. Roanoke Gas is served directly by two primary pipelines. These two pipelines deliver all of the natural gas supplied to the Company’s customers. Depending on weather conditions and the level of customer demand, failure of one or both of these transmission pipelines could have a major adverse impact on the Company.

The Company has both a defined benefit pension plan (the “pension plan”) and a postretirement benefit plan (the “postretirement plan”). The pension plan covers substantially all of the Company’s employees and provides retirement income based on years of service and employee compensation. The postretirement plan provides certain healthcare and supplemental life insurance benefits to retired employees who meet specific age and service requirements. Net pension plan and postretirement plan expense recorded by the Company is detailed as follows:

 

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

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

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

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level 3).

 

The fair value of the interest rate swaps, included in the line item “Fair value of marked-to-market transactions”, is determined by using the counterparty’s proprietary models and certain assumptions regarding past, present and future market conditions.

 

The fair value of the notes receivable are estimated by discounting future cash flows based on a range of rates for similar investments adjusted for management’s expectation of credit and other risks. The fair value of the note payable is estimated by using the interest rate under the Company’s line-of-credit agreement which renewed at the same time as the term note. Both the line-of-credit and term note have a term of one year. The fair value of long-term debt is estimated by discounting the future cash flows of the fixed rate debt at rates extrapolated based on current market conditions. The variable rate long-term debt has interest rate swaps that effectively convert such debt to a fixed rate. The values of the swap agreements are included in the first table above.

The Company has evaluated subsequent events through the date the financial statements were issued. There were no items not otherwise disclosed which would have materially impacted the Company’s condensed consolidated financial statements.

 

ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Forward-Looking Statements

This report contains forward-looking statements that relate to future transactions, events or expectations. In addition, RGC Resources, Inc. (“Resources” or the “Company”) may publish forward-looking statements relating to such matters as anticipated financial performance, business prospects, technological developments, new products, research and development activities and similar matters. These statements are based on management’s current expectations and information available at the time of such statements and are believed to be reasonable and are made in good faith. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements. In order to comply with the terms of the safe harbor, the Company notes that a variety of factors could cause the Company’s actual results and experience to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance, development and results of the Company’s business include, but are not limited to those set forth in the following discussion and within Item 1A “Risk Factors” of the Company’s 2012 Annual Report on Form 10-K. All of these factors are difficult to predict and many are beyond the Company’s control. Accordingly, while the Company believes its forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in the Company’s documents or news releases, the words, “anticipate,” “believe,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “budget,” “assume,” “indicate” or similar words or future or conditional verbs such as “will,” “would,” “should,” “can,” “could” or “may” are intended to identify forward-looking statements.

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

The three-month and nine-month earnings presented herein should not be considered as reflective of the Company’s consolidated financial results for the fiscal year ending September 30, 2013. The total revenues and margins realized during the first nine months reflect higher billings due to the weather sensitive nature of the gas business. Improvement or decline in earnings for the balance of the fiscal year will depend primarily on non-weather sensitive industrial consumption and the level of operating and maintenance costs incurred.

Resources is an energy services company primarily engaged in the regulated sale and distribution of natural gas to approximately 58,300 residential, commercial and industrial customers in Roanoke, Virginia and the surrounding localities through its Roanoke Gas Company (“Roanoke Gas”) subsidiary. Natural gas service is provided at rates and for terms and conditions set by the Virginia State Corporation Commission (“SCC”).

Resources also provides certain unregulated services through Roanoke Gas and its other subsidiaries. Such unregulated operations represent less than 3% of total revenues and margin of Resources on an annual basis.

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

The SCC authorizes the rates and fees that the Company charges its customers for regulated natural gas service. The Company has in place certain approved rate mechanisms that reduce some of the volatility in earnings associated with variations in winter weather and the cost of natural gas.

Roanoke Gas has in place a weather normalization adjustment mechanism (“WNA”) based on a weather measurement band around the most recent 30-year temperature average (“normal"). Because the SCC authorizes billing rates for the utility operations of Roanoke Gas based on normal weather, warmer than normal weather may result in the Company failing to earn its authorized rate of return. Therefore, the WNA provides the Company with a level of earnings protection when weather is significantly warmer than normal and provides its customers with price protection when the weather is significantly colder than normal. The WNA mechanism provides for a weather band of 3% above and below the 30-year 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. The annual WNA period extends from April to March. At the end of the most recent WNA period ended March 31, 2013, total heating degree days fell within the 3% weather band and thereby did not trigger the WNA mechanism for the period. Weather during the corresponding WNA period for the prior year was significantly warmer than normal, and the Company recorded $1,740,000 in additional revenues to reflect the impact of the WNA for weather that was 22% above the 30-year average. Although the WNA mechanism provides the Company with a method to recover margin not realized for warmer weather above the 3% weather band, the statistical models used in determining the WNA amount do not provide for a precise recovery of lost margin and therefore will vary in their results based not only on the magnitude of weather variation during the total WNA period but also on the variation for each month.

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 factor applied to the cost of inventory is based on the Company’s weighted average cost of capital including interest rates on short-term and long-term debt and the Company’s authorized return on equity. During times of rising gas costs and rising inventory levels, the Company recognizes revenues to offset higher financing costs associated with higher inventory balances. Conversely, during times of decreasing gas costs and lower inventory balances, the Company recognizes less inventory carrying cost ("ICC") revenue as financing costs are lower. ICC revenues decreased by $49,000 for the quarter and $293,000 for the nine-month period compared to the same periods last year. This decrease in ICC revenue resulted from the decline in the average value of inventory during the period in combination with an SCC mandated revision to the ICC calculation model which shifted a portion of revenue previously included as part of the ICC revenue into the Company's non-gas base rates. Management estimates this methodology change will reduce annual ICC revenues by approximately $120,000, as those revenues are now included in the customer base charge and volumetric rate.

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 investment in inventory declines due to a reduction in commodity prices, net income will be negatively affected as carrying cost revenues decrease by a greater amount than short-term financing costs decrease. The inverse occurs when inventory costs increase.

Three Months Ended June 30, 2013:

Net income increased by $57,805 for the quarter ended June 30, 2013 compared to the same period last year. Implementation of a non-gas rate increase and colder weather more than offset higher expenses.

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

Regulated natural gas margins from utility operations increased from the same period last year primarily as a result of the combination of the implementation of a non-gas rate increase, higher delivered volumes and the implementation of a SAVE rider more than offsetting a reduction in inventory carrying cost revenues. The increased natural gas base rates were effective for service rendered on and after November 1, 2012 and were designed to provide $649,639 in additional annual non-gas revenues, split between the customer base charge component and volumetric components, as provided for in the final order issued by the SCC. The increase in delivered volumes is attributable to cooler spring weather compared to the same period last year. Residential and commercial volumes increased by 17% while industrial and transportation volumes, which tend to be less weather sensitive, were nearly unchanged. The Company also recognized $69,094 in SAVE Plan revenues as discussed in further detail under the Regulatory section below. Although the average natural gas inventory storage balances declined by 4% during the quarter, inventory carrying cost revenues declined by 24% due to a change in calculation methodology as discussed above.

The components of the gas utility margin increase are summarized below:

Other margins declined by $44,078 from the same period last year primarily due to cost over-runs on work related to a one-time contract that was completed in June and reductions in the level of work performed under another contract. More than half of the "Other" revenues and margins are subject to variations in the level of activity and generally are associated with service contracts that have a limited duration or are subject to renewal on an annual or semi-annual basis. Current service contracts extend through the remainder of the fiscal year; however, any continuation beyond fiscal 2013 is uncertain.

Operation and maintenance expenses increased by $46,423, or 2%, as higher bad debt expense, stock option expense, contracted services and corporate insurance premiums offset increases in capitalized overheads. Bad debt expense increased by $69,000 due to higher billings. The Company recognized $42,000 in expense related to the granting of stock options as discussed in Note 11. Corporate property and liability insurance increased by $19,000 due to higher premiums and increased general liability coverage limits. Contracted services increased $93,000 due to network services support and additional costs related to an SCC mandated meter setinspection and remediation program. These increased costs were partially offset by an increase in overheads capitalized related to LNG (liqufied natural gas) production and higher level of capital spending. The remaining differences in operation and maintenance expenses were related to various other minor fluctuations in other expenses.

General taxes increased by $34,908, or 10%, primarily due to higher property taxes associated with increases in utility property.

 

Depreciation expense increased by $56,988, or 5%, on a corresponding increase in utility plant investment primarily due to the distribution pipeline replacement program.

Other income (expense), net, moved from an income position to a net expense position due to the payoff of the note receivable from ANGD, LLC on February 1, 2013 as discussed in Note 4.

Interest expense was virtually unchanged as the Company’s total debt position remained at the $28,000,000 level during the quarter.

Income tax expense increased by $29,048, which corresponds to the increase in pre-tax income for the quarter. The effective tax rate was 38% for the current period and 43% for the same period last year.

Net income was nearly unchanged, decreasing by $7,554 for the nine months ended June 30, 2013 compared to the same period last year. Higher operation and maintenance expenses and depreciation offset implementation of a non-gas rate increase.

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

Total operating revenues for the nine months ended June 30, 2013 compared to the same period last year increased due to significant increases in delivered volumes partially offset by lower cost of natural gas, reduced inventory carrying cost revenues and the absence of WNA revenues. Total natural gas deliveries rose by 16% due to a 26% increase in heating degree days. In addition, natural gas commodity prices resulted in a 7% per unit reduction in the cost of natural gas reflected in cost of sales. Prior year revenues also included $1,747,000 in WNA revenues to offset the effects of lost margin due to warmer weather as discussed above. Other revenues increased by 6%.

 

Regulated natural gas margins from utility operations increased by $592,538, or 3%, over the same period last year due to the net effects of the following items. Residential and commercial volumes (which tend to be more weather sensitive than transportation and industrial volumes) increased by 23%, corresponding to a 26% increase in the number of heating degree days for the period. Industrial volumes were nearly unchanged from the same period last year. The margin increase generated by the higher residential and commercial volume activity, however, was mostly offset by the $1,747,000 in WNA revenues recorded last year due to much warmer weather. The implementation of the non-gas rate increase effective November 1, 2012 and the SAVE Plan revenues beginning January 1, 2013 provided for higher margins, while margins attributable to ICC revenue declined due to lower average gas in storage during the period and a change in the ICC revenue calculation model. The components of the regulated net margin increase are summarized below:

Other margins declined by $64,828 primarily due to reductions in the level of other services contract work during the period.

Operation and maintenance expenses increased by $242,815 or 3%, for the nine-month period ended June 30, 2013 compared to the same period last year. Higher labor, contracted services, bad debts, stock option expense and corporate insurance costs more than offset increases in capitalized overheads. Labor and contracted services increased by $293,000 primarily due to timing of leak surveys and pipeline right-of-way clearing, which were completed in the first quarter, costs related to an SCC mandated meter installation inspection and remediation program and network services support and training. Bad debt expense increased $56,000 due to higher gross customer billings. The Company recognized $42,000 in expense related to the granting of stock options. Corporate property and liability insurance increased by $67,000 due to higher premiums and increased general liability coverage limits. These higher costs were partially offset by greater capitalization of overheads due to higher level of capital expenditures and increased LNG production.

General taxes increased $90,891, or 9%, for the nine-month period ended June 30, 2013 compared to the same period last year primarily related to higher property taxes associated with increases in utility property.

Depreciation expense increased by $179,351, or 6%, corresponding to the increase in utility plant investment.

Other income (expense), net declined by $28,379 due to the reduction in interest income from the payoff of the ANGD note in February 2013.

Interest expense remained nearly unchanged as borrowing under the Company’s line-of-credit was minimal during the period.

Income tax expense declined by $4,567, or less than 1%, which corresponds to the decrease in pre-tax income. The effective tax rate was 38% for both periods.

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 it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. There have been no changes to the critical accounting policies as reflected in the Company’s Annual Report on Form 10-K for the year ended September 30, 2012.

Roanoke Gas uses a third party as an asset manager to manage its pipeline transportation and storage rights and gas supply inventories and deliveries. In return for being able to utilize the excess capacities of the transportation and storage rights, the third party pays Roanoke Gas a monthly utilization fee, which is used to reduce the cost of gas for customers. The current agreement expires in October 2013. The Company is currently evaluating bid responses from asset managers for a new contract. The Company expects to complete its evaluation and make its final selection during its fiscal fourth quarter.

 

On November 1, 2012, Roanoke Gas Company placed into effect new base rates, subject to refund, that provide for approximately $1,840,000 in additional annual non-gas revenues. On March 21, 2013, the Company reached a stipulated

agreement with the SCC staff for a non-gas rate award in the amount of $649,639 in additional annual non-gas revenues. On April 16, 2013, the SCC issued its final order approving the increase in annual non-gas revenues agreed to in the stipulation. During May 2013, the Company completed its refund, including interest, for the difference between the rates placed into effect on November 1 and those approved in the final order.

Beginning in January 2013, the Company started billing a separate rider on customer bills related to its SAVE (Steps to Advance Virginia’s Energy) Plan. The SCC approved the Company’s SAVE Plan application on July 25, 2012. The SAVE plan is designed to facilitate the accelerated replacement of aging natural gas infrastructure assets by providing the Company with a means to recover depreciation and related 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 SAVE Plan provides the Company with a more timely mechanism for recovering the cost of its renewal program. Previously, the Company could only recover these costs and earn a return on rate base on a prospective basis after filing and implementing a non-gas rate increase. The Company has billed its customers $69,094 and $138,351 in SAVE Plan revenues for the quarter and year-to-date, respectively.

In the second quarter, the SCC issued new inspection protocols for meter sets that require all meter sets to be inspected once every three years, on a continuous cycle, beginning in May 2013. The Company began the process in its fiscal third quarter and expects expenses to increase when the inspection and remediation process is fully implemented in fiscal 2014. The Company plans to seek full recovery of these expenses through an expedited rate case. As a result of these increased costs and other factors, the Company filed notice with the SCC on July 16, 2013 of its intent to file an expedited rate case. The amount of increase in non-gas rates to be requested has not yet been determined.

Due to the capital intensive nature of the utility business, as well as the related weather sensitivity, the Company’s primary capital needs are the funding of its continuing construction program, the seasonal funding of its natural gas inventories, accounts receivable and payment of dividends. To meet these needs, the Company relies on its operating cash flows, line-of-credit agreement, long-term debt and capital raised through the Company’s Dividend Reinvestment and Stock Purchase Plan (“DRIP”).

Cash and cash equivalents increased by $1,857,974 for the nine-month period ended June 30, 2013 compared to a $7,797,379 increase for the same period last year. The significant reduction in cash flow was primarily due to the special $1.00 per share dividend paid by the Company on December 17, 2012 and, to a lesser extent, to less cash generated by operations and higher capital expenditures related to the Company’s pipeline renewal program. The following table summarizes the sources and uses of cash:

 

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 the related cash flows. Generally, operating cash flows are positive during the second and third quarters as a combination of earnings, declining storage gas levels and collections on customer accounts all contribute to higher cash levels. During the first and fourth quarters, operating cash flows generally decrease due to increases in natural gas storage levels, rising customer receivable balances and construction activity.

For the nine months ended June 30, 2013, cash flow provided by operations decreased by $1,748,022 from the prior year primarily due to a smaller reduction in storage inventory balances during the current nine-month period compared to the prior year. For the past several years, natural gas commodity prices have trended down with prices leveling off during the 2012 summer storage fill months. As a result, the average price of gas in storage declined from $4.90 per decatherm at September 30, 2011 to $3.50 per decatherm at September 30, 2012. The current price of gas in storage increased slightly to approximately $4.00. Therefore, the cash generated from the change in inventory balances during the current year was related

to the reduction in storage volumes, while last year the change in inventory balance was due to both a decline in the volume and the price of gas in storage.

Investing activities are generally composed of expenditures under the Company’s construction program, which primarily involves replacing aging bare steel and cast iron pipe with new plastic or coated steel pipe, improvements to the LNG plant, and to a lesser degree, expanding its natural gas system to meet the demands of customer growth. Cash flows used in investing activities increased by $388,852 due to an increased level of capital expenditures. Total capital expenditures were $6,883,039 and $6,492,885 for the nine-month periods ended June 30, 2013 and 2012, respectively. The increase in capital expenditures is attributable to the continued focus by the Company on its pipeline renewal program. Current year capital expenditures would have been higher if not for prolonged periods of rain which limited construction activity. The Company’s current plan includes a four to six year time horizon to finish replacing the remaining bare steel and cast iron pipe within its natural gas distribution system. In order to meet this goal, the Company expects capital expenditures to remain at elevated levels for the next few years. The depreciation add back to operating cash flows is expected to provide approximately 50% of the funding for the current year’s projected capital expenditures, with the balance of funding dependent on other sources including net income, available cash and corporate borrowing activity.

Financing activities generally consist of long-term and short-term borrowings and repayments, issuance of stock and the payment of dividends. As discussed above, the Company uses its line-of-credit arrangement to fund seasonal working capital needs as well as provide temporary financing for capital projects. Cash flow used in financing activities increased by $3,802,531, from $1,589,176 to $5,391,707, primarily due to the special $1.00 per share dividend paid by the Company on December 17, 2012. The special dividend totaled $4,675,337, of which $425,630 was returned to the Company under the DRIP plan to purchase 21,951 shares of stock. Most of the remaining difference relates to proceeds received from the $865,000 payoff of the balance of the ANGD note in February. The Company accessed its line-of-credit in November 2012 to provide temporary financing during the winter season. The Company has been able to finance operations with its operating cash flow without needing to access its line-of-credit over the last few years as cash flows have been positively affected by declining natural gas prices resulting in lower natural gas storage balances and accounts receivable in addition to accelerated and bonus tax depreciation deductions which have limited federal corporate income tax payments. However, with natural gas prices appearing to have leveled off and an increasing focus on the Company’s pipeline replacement program, the Company expects to utilize its line-of-credit more often in the future to provide funding for its operations.

Effective March 31, 2013, the Company entered into a new line-of-credit agreement. The new agreement maintained the same terms and rates as provided for under the expired agreement. 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 the multi-tiered borrowing limits to accommodate seasonal borrowing demands and minimize overall borrowing costs with available limits ranging from $1,000,000 to $7,000,000 during the term of the agreement. The line-of-credit agreement will expire March 31, 2014, unless extended. 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.

Effective March 31, 2013, the Company also executed an unsecured term note in the amount of $15,000,000. This term note essentially extends the maturity date of the prior term note to March 31, 2014 and retains all other terms and conditions provided for in the original promissory note. The Company anticipates being able to renew this note on comparable terms as currently in place until such time the note co-terminates with the corresponding interest rate swap on November 30, 2015.

At June 30, 2013, the Company’s consolidated capitalization, including notes payable, was 64% equity and 36% debt.

 

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates and commodity prices. Interest rate risk is related to the Company’s outstanding long-term and short-term 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.

The Company is exposed to market risk related to changes in interest rates associated with its borrowing activities. At June 30, 2013, the Company had no balances outstanding under its line-of-credit. The Company did, however, access its line-of-credit during the Company's first fiscal quarter to provide temporary working capital funding. A hypothetical 100 basis point increase in market interest rates applicable to the Company’s variable rate debt outstanding during the period would have resulted in an increase in interest expense for the current year of less than $1,000. The Company also has a $15,000,000 note payable and a $5,000,000 intermediate term variable rate note both of which are currently being hedged by fixed rate interest swaps. The remaining $8,000,000 balance of the long-term debt is at fixed rates.

The Company manages the price risk associated with purchases of natural gas by using a combination of liquefied natural gas (LNG) storage, underground storage gas, fixed price contracts, spot market purchases and derivative commodity instruments including futures, price caps, swaps and collars.

At June 30, 2013, the Company had no outstanding derivative instruments to hedge the price of natural gas. The Company had 1,781,494 decatherms of gas in storage, including LNG, at an average price of $4.09 per decatherm. 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 PGA mechanism.

 

ITEM 4 – CONTROLS AND PROCEDURES

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

As of June 30, 2013, the Company completed an evaluation, under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2013.

Management routinely reviews the Company’s internal control over financial reporting and makes changes, as necessary, to enhance the effectiveness of the internal controls over financial reporting. There were no changes in the internal controls over financial reporting during the fiscal quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

Part II – Other Information

ITEM 1 – LEGAL PROCEEDINGS

No changes.

ITEM 1A – RISK FACTORS

No changes.

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

None.

ITEM 3 – DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 – MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 – OTHER INFORMATION

None.

ITEM 6 – EXHIBITS

 

 

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned there unto duly authorized.