10-K 1 f10k2006.htm 2006 10-K Converted by EDGARwiz


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K

(Mark One)

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   

For the transition period from ______________________ to _________________________


Commission file number 001-10608                                 


Florida Public Utilities Company

(Exact name of the registrant as specified in its charter)


 

 

 

 

 

 

 

 

 

Florida

 

59-0539080

(State or other jurisdiction of Incorporation or organization)

 

(I.R.S. Employer Identification Number)


401 South Dixie Highway, West Palm Beach, FL  33401

(Address of principal executive offices, Zip Code)


Registrant’s telephone number, including area code    (561) 832-0872


Securities registered pursuant to section 12(b) of the Act:


 

 

 

 

 

 

 

 

 

Title of each class

 

Name of each exchange on which registered

Common Stock par value $1.50 per share

 

American Stock Exchange



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

__________________________________________________________________________________

 (Title of class)

__________________________________________________________________________________

(Title of class)



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


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     [X] No


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.  [X] Yes     [  ] No


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a non-accelerated filer.  See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer [  ]

Accelerated filer [  ]

Non-accelerated filer [X]


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


As of June 30, 2006, the aggregate market value of the Registrant’s Common Stock held by non-affiliates (based upon the closing price of the Common Stock on that date on the American Stock Exchange) was approximately $71,300,000.


On February 9, 2007, 6,024,739 shares of the Registrant’s $1.50 par value common stock were outstanding.


DOCUMENTS INCORPORATED BY REFERENCE


Portions of the registrant’s Proxy Statement for the May 8, 2007 Annual Meeting of Shareholders are incorporated by reference in Part III hereof.


PART I


Item 1.   Business


General

Florida Public Utilities Company (FPU) was incorporated on March 6, 1924 and reincorporated on April 29, 1925 under the 1925 Florida Corporation Law. We provide natural gas, electricity and propane gas to residential, commercial and industrial customers in Florida. We do not produce energy and are not a generating utility. Our regulated segments sell natural gas and electricity to approximately 82,000 customers, and our unregulated segment sells propane gas through a wholly owned subsidiary, Flo-Gas Corporation, to approximately 13,000 customers. We also sell merchandise and other service related products on a limited basis as a complement to the natural and propane gas segments.


Our three primary business segments are aligned with our products and are natural gas, electric and propane gas.  The Florida Public Service Commission (FPSC) regulates the natural gas and electric segments. We operate through five divisions based on geographic areas:


(1)

South Florida Division - provides natural and propane gas to customers in West Palm Beach, Palm Beach Gardens, North Palm Beach, Jupiter, Riviera Beach, Palm Beach, Lake Worth, Royal Palm Beach, Wellington, Boynton Beach, Delray Beach, Boca Raton, Lauderdale Lakes, Deerfield Beach, Stuart, Palm City and other areas near these cities.

(2)

Central Florida Division - provides natural and propane gas to customers in Sanford, Deland, Deltona, DeBary, Orange City, Lake Mary, Winter Springs, New Smyrna Beach, Edgewater, Longwood, Port Orange and other areas near these cities.

(3)

Northwest Florida Division - provides electricity to customers in Marianna, Bristol, Altha, Cottondale, Malone, Alford and other areas near these cities.

(4)

Northeast Florida Division - provides electricity and propane gas to customers in Fernandina Beach, Jacksonville, Callahan, Yulee and other areas near these cities.

(5)

West Florida Division - provides propane gas to customers in Dunnellon, Inglis, Crystal River, Inverness, Brooksville and other areas near these cities.


Business Environment

Natural and propane gas are some of the most popular forms of energy today.  Gas is used for heating, cooling, cooking, backup generation and decorative lighting by businesses and homeowners and in many other ways by various industries.  Natural gas is also used in combination with other fuels to improve environmental performance and decrease pollution in the generation of electricity.


Natural and propane gas have seen increased demand in Florida as a result of the recent hurricanes and the popularity of generators. Generators themselves do not impact usage significantly for a region; however, gas appliances have been added as a result of generator popularity, and that does increase gas usage. Prices of natural and propane gas have decreased during 2006 due in part to the absence of a hurricane affecting the Gulf of Mexico.


As a result of historically high natural gas costs in 2005, alternatives such as coal and nuclear power for generation of electricity have seen increased interest.  Our sales in the electric segment have not been impacted by higher electricity costs due to our long-term favorable fixed price contracts for purchasing electricity.  However, our long-term contract ended at the end of 2006 for our Northeast division and our long-term contract will end at the end of 2007 for our Northwest division. We now have new contracts in place with pricing much closer to current market price. Our electric prices are expected to significantly increase.  Although this will not directly impact our income from operations because increased fuel costs are passed through to the customer, this may impact the number of units sold and decrease income from operations as a result of less usage.


Because of the hurricanes in 2004 and 2005, the electric industry in Florida has seen increased interest in improving reliability of electric services during and after hurricanes. Regulators have been researching the issue and have introduced new storm preparedness requirements to improve electric reliability with storm preparedness rules regarding pole inspections, strengthened design specifications for wind loading, vegetation management practices and installation of underground facilities for electric distribution and transmission systems.  We are seeking rate relief and implementation for these new requirements in 2007.


Business Segments

We are organized in three operating and reporting segments: natural gas, electric and propane gas. We are also involved in limited merchandise sales and other services within our natural gas and propane gas areas to complement these segments. For information concerning revenues, operating income and identifiable assets of each of our segments, see Note 13 in Notes to Consolidated Financial Statements.


Natural Gas

Natural gas is primarily composed of methane, which is a colorless, odorless fuel that burns cleaner than many other traditional fossil fuels.  Odorant is added to enable easy detection of a gas leak.


We provide natural gas to customers in our South and Central Florida divisions. The vast majority of the natural gas we distribute is purchased in the Gulf Coast region, both onshore and offshore.


We use Florida Gas Transmission (FGT) as our natural gas pipeline in peninsular Florida. FGT is under the jurisdiction of the Federal Energy Regulatory Commission (FERC).  We use gas marketers and producers to procure all gas supplies for our markets. We use Florida City Gas and Indiantown Gas Company to provide wholesale gas transportation services in areas distant from our interconnections with FGT. We pass all fuel costs on to our customers.  We also transport natural gas for customers who purchase their own gas supplies and arrange for pipeline transportation.  Our operating results are not adversely affected if our customers purchase gas from third parties because we do not profit on the fuel portion of sales.


Our natural gas revenues are affected by the rates charged to customers, supply costs for natural gas purchased for resale, economic conditions in our service areas and weather. Although the FPSC permits us to pass through to customers the increase in price for our gas supply, higher rates may cause customers to purchase less natural gas.


Our current portfolio of natural gas customers is reasonably diverse, with the largest customer using natural gas for the generation of electricity.  We are not dependent on any single natural gas customer for over ten percent of our total natural gas revenues.


The FPSC approved joint transportation and territorial agreements with Indiantown Gas Company in October 2006. We plan to transport natural gas through Indiantown’s system to new developments. In the early phase, Indiantown Gas Company will provide operational and customer service related work. We also began construction in the Indiantown area to install natural gas mains in the first phase of a development for approximately 100 homes. Two more new developments are slated to break ground in 2007 for construction of approximately 1,000 homes.


Electric

We provide electricity to our customers in our Northwest and Northeast Florida divisions.  Wholesale electricity is purchased from two suppliers; Gulf Power Company and JEA (formerly Jacksonville Electric Authority).  In 1996, we executed ten-year fixed-price purchased power contracts with both suppliers. Gulf Power Company provides electric power to the Northwest division and JEA provides electric power to the Northeast division.  These long-term contracts provided our customers with the lowest consumer electric rates in Florida.


During 2006 we completed negotiations and executed final contracts for the supply of electricity in our Northeast division from JEA beginning January 1, 2007 and our Northwest division from Gulf Power Company beginning in January 1, 2008. We are seeking approval of the contract with Gulf Power Company from the FPSC in 2007. We expect that rates charged to our customers will significantly increase when the new contracts become effective in 2007 and 2008 because the prices are closer to market price. We are unable to estimate what impact higher rates could have on electric consumption, but electricity usage could decrease.


The Northwest and Northeast divisions experience a variety of weather patterns.  Hot summers and cold winters produce year-round electric sales that normally do not have highly seasonal fluctuations.  None of the electric segment’s customers represent more than ten percent of our total electric revenues.


The electric utility industry has not been deregulated in the state of Florida.  All customers within a given service or franchise area purchase from a single electricity provider in that area.


Propane Gas

We provide propane gas to customers in our Northeast, West, Central and South Florida divisions and can purchase our propane gas supply from several different wholesale companies. Propane gas is delivered to Florida by barges and railcars to terminals in Tampa and Ft. Lauderdale, and through the Dixie Pipeline terminus at Alma and Albany, Georgia. Propane gas is also delivered by transport to our facilities and directly to a customer’s premise. We believe that the propane gas supply infrastructure is adequate to meet the needs of the industry in Florida for the foreseeable future.


Propane gas is not as affected by environmental regulations as other petroleum products. However, propane gas is a hazardous material and as such is subject to strict code enforcement and safety requirements.


As with natural gas, the sales volume of propane gas is affected by the season and the weather.  Typically, Florida has a tourist season that coincides with the winter months. The propane gas segment's sales volumes and revenues are closely balanced between residential and commercial customers.  We employ two strategies to become less weather dependent, concentrating on the forklift propane gas cylinder exchange market and marketing propane gas appliances not used for heating air.  We believe that water heaters and forklift cylinder exchange accounts are good ways to become less weather reliant.  None of the propane gas segment’s customers represent more than ten percent of our total propane gas sales volume or revenues.


Strategy

Our strategy is to leverage our expertise in the natural gas, electric and propane gas distribution business to assist us in consistently meeting our customer’s expectations. Our core focus is to build mutually beneficial relationships with builders, developers and customers with high-energy usage requirements. Included in our strategy is a plan to enhance our future success by expanding our service territory into new areas with high growth potential.


Competition

We do not face substantial competition in our electric divisions.  This is because no other competitor can currently provide the same energy in our areas due to FPSC regulations and territorial agreements between utilities. In addition, natural gas as an alternative fuel is only available in a small area served by our electric divisions. Although our natural gas segment operates with the same types of guidelines, there is competition in our natural gas segment from electric utilities. Normally each home will have electricity as a base fuel and natural gas as an alternative source of energy used for cooking and heating. Electricity competes with natural gas, in large part based on the cost of fuel. Our propane gas segment is unregulated and faces competition from other suppliers of propane gas as well as alternative energy source suppliers. Competition in the propane gas segment is primarily based on price and service.


Rates and Regulation

The natural gas and electric segments are highly regulated by the FPSC.  The FPSC has the authority to regulate our rates, conditions of service, issuance of securities and certain other matters affecting our natural gas and electric operations.  As a result, FPSC regulation has a significant effect on our results of operations.  The FPSC approves rates that are intended to permit a specified rate of return on investment.  Our rate tariffs allow the cost of natural gas and electricity to be passed through to customers.  Increases in the operating expenses of the regulated segments may require us to request increases in the rates charged to our customers.  The FPSC has granted us the flexibility of automatically passing on increased expenses for certain fuel costs to customers.  Other operational expenses, such as pension and medical expenses require us to petition the FPSC for rate increases.  The FPSC is likely to grant rate increases to offset increased expenditures necessary for business operations.  We successfully petitioned for an electric rate increase, which became effective on March 17, 2004, and for a natural gas rate increase that went into effect on November 18, 2004.  We are currently seeking electric rate relief in 2007 for the recent storm preparedness requirements implemented to improve reliability of electric utility systems.


We are subject to federal and state regulation with respect to soil, groundwater, employee health and safety matters and to environmental regulations issued by the Florida Department of Environmental Protection (FDEP), the United States Environmental Protection Agency (EPA) and other federal and state agencies.


Prior to the widespread availability of natural gas, we manufactured gas for sale to our customers or purchased utility assets from other companies that manufactured gas. The process for manufacturing gas produced by-products and residuals such as coal tar. The remnants of these residuals are sometimes found at former gas manufacturing sites. These sites face environmental regulation from various agencies including the FDEP and EPA on necessary cleanup and restoration.


Franchises

We hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity.  Generally, these franchises have terms ranging from 10 to 30 years and terminate on varying dates. We are currently in negotiations with certain municipalities for new service areas within our current operating divisions, and renewals of existing franchises. We continue to provide services to these municipalities and do not anticipate any interruption in our service.


Employees

As of January 18, 2007, we had 362 employees, of which 9 were part-time and 2 were temporary. Of these employees, 175 were covered under union contracts with two labor unions, the Internal Brotherhood of Electric Workers and the International Chemical Workers Union. We believe that our labor relations with employees are good.


Available Information

We file periodic reports including our Form 10-Qs, Form 10-Ks, and Form 8-Ks with the Securities and Exchange Commission (SEC). The most recent copies of Form 10-Qs and Form 10-Ks as well as a copy of our Code of Ethics Policy can be obtained through our website (http://www.fpuc.com).


Item 1A.   Risk Factors


A substantial portion of our revenues and, to a large extent, our profitability, depends upon rates determined by the FPSC.


FPSC regulates many aspects of our natural gas and electric operating segments, including the retail rates that we may charge customers for natural gas and electric service.  Our retail rates are set by the FPSC using a cost-of-service approach that takes into account our historical operating expenses, our fixed obligations and recovery of our capital investments, including potentially stranded obligations. Using this approach, the FPSC sets rates at a level calculated to recover such costs, adjusted to reflect known and measurable changes, and a permitted return on investment.  Any rate adjustments to recover increased costs or to otherwise improve our profitability must be obtained through a petition filed with the FPSC, which is referred to as a rate case.  The rates permitted by the FPSC in rate cases will determine a substantial portion of our revenues for succeeding periods and may have a material impact on our consolidated earnings, cash flows and financial position, as well as our ability to maintain our common stock dividend at current levels or to increase our dividend in the future.


Some of our natural gas and electric service costs may not be fully recovered through retail rates.


Our natural gas and electric service retail rates, once established by the FPSC, remain fixed until changed in a subsequent rate case.  We may at any time elect to file a rate case to request a change in our rates or intervening parties may request that the FPSC review our rates for possible adjustment, subject to any limitations that may have been ordered by the FPSC. Earnings could be reduced to the extent that our operating costs increase more than our revenues during the period between rate cases, which may occur because of maintenance and repair of plants, fuel and purchased power expenses, employee or labor costs, inflation or other factors.  In addition, even if we decide to file rate cases, our requests for rate adjustments in such rate cases may be rejected.  Other parties to a rate case or the FPSC staff may contend that our current rates, or rates proposed in a rate case, are excessive and our petition for rate adjustments may be denied on that or another basis.


Our segments are sensitive to variations in weather.


Our segments are affected by variations in general weather conditions and unusually severe weather. We forecast energy sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather could have a material impact on energy sales. Unusual weather, such as hurricanes, could also adversely affect operating costs and sales.


Our natural gas and propane gas customers use gas primarily for heating purposes.  As a result, our natural gas and propane gas sales peak in the winter and are more weather sensitive than electricity sales, which peak in both summer and winter periods. Mild winter weather in Florida can be expected to negatively impact results from our natural gas and propane gas operations. Severe weather conditions could also interrupt or slow down service and increase the operating costs of all our segments.


We operate in an increasingly competitive industry, which may affect our future earnings.


Natural Gas

The natural gas distribution industry has been subject to competitive forces for several years. We receive our supply of natural gas at thirteen city gate stations connected to an interstate pipeline system owned by FGT and one gate station connected to an intrastate pipeline owned by Florida City Gas Company.  Gulfstream Natural Gas System currently also serves peninsular Florida with interstate natural gas transmission service; however we cannot predict if this system will be extended to areas near our existing facilities and how it could affect our natural gas operations.


Electric

The U.S. electric power industry has been undergoing restructuring.  There is competition in wholesale power sales on a national level. Some states have mandated or encouraged competition at the retail level. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect our financial condition and results of operations.  To the extent competitive pressures increase and the pricing and sale of electricity assumes more of the characteristics of a commodity business, the economics of our electric operating segment may come under increasing pressure. In addition, regulatory changes may increase access to electricity transmission grids by utility and non-utility purchasers and sellers of electricity, thus potentially resulting in a significant number of additional competitors.


Propane Gas

Our propane gas business is our only non-regulated business segment.  Because the propane gas business is not regulated, we face significant competition in this segment.  Our propane gas business competes directly with other distributors of propane gas, and other sources of energy including natural gas and electric.  We may encounter increased competition in the propane gas business in the future.  Our inability to compete effectively in the propane gas business, whether on the basis of price, customer service, alternative energy sources or otherwise, could have a material adverse effect on our financial condition and results of operations.


Our business could be adversely affected if our supply of natural gas is interrupted.


FGT’s pipeline system transports all of our natural gas.  FGT is owned by Citrus Corporation, which is jointly owned by Cross Country Energy Corporation and El Paso Corporation. Our ability to receive our normal supply of natural gas could be adversely affected by an interruption in FGT’s service.


General economic conditions may adversely affect our segments.


Our segments are affected by general economic conditions. The consumption of the energy we supply is directly tied to the economy. A downturn in the economy in our local areas of operations, as well as on the state, national and international levels, could adversely affect the performance of our segments.  Changes in political climate, including terrorist activities, could further negatively impact our performance. If tourism is down, then the demand for the energy we supply is reduced.


Commodity price changes may affect the operating costs and competitive position of our segments.


Our segments are sensitive to changes in coal, gas, oil and other commodity prices. If we are unable to increase the rates we charge to customers to reflect increases in these commodity prices, our margins and earnings will be lowered.  If increased prices for any of these commodities persist for substantial periods, our competitive position could be adversely affected by customers who switch to cheaper energy sources.  Further, natural gas prices have been increasingly volatile and, accordingly, the earnings from our natural gas operations are increasingly difficult to predict.


We could incur material expenses as a result of our obligations to comply with existing and new environmental laws and regulations.


We are subject to environmental regulations in connection with the ongoing conduct of our business and to civil and criminal liability for failure to comply with these regulations. In addition, new environmental laws and regulations, or new interpretations of existing laws and regulations, affecting our operations or facilities may be adopted which may cause us to incur additional material expenses.


We are subject to federal and state legislation with respect to soil, groundwater, employee health and safety matters and to environmental regulations issued by the Florida Department of Environmental Protection (FDEP), the EPA and other federal and state agencies.  We may incur material future expenditures in order to comply with these existing environmental laws and regulations.


We rely on a limited number of natural gas and electric suppliers, the loss of which could materially adversely affect our financial condition and results of operations.


Two pipeline suppliers under several contracts having expiration dates from 2007 to 2023 transport our natural gas to us.  These contracts have provisions, which allow us to extend the terms ranging from 2020 to 2032.  Our electric services are provided by two suppliers under contracts, which expire in 2007 and 2017. We have renegotiated a new contract for the one that is set to expire in 2007 with the same supplier for electric service beginning in 2008 which we are currently awaiting approval for from the FPSC.  If we were to lose any of these contracts, we might not be able to replace the corresponding energy source on acceptable terms, if at all.  In addition, in the event of the expiration of the contracts, we might not be able to renew them on favorable terms, if at all.  As a result, the loss of any of these suppliers, the terminations of any of these supply contracts or the non-renewal of any of these supply contracts before or upon their expiration could have material adverse effects on our financial condition and results of operations.


New supply contracts could result in substantial increases to our prices, and could materially adversely affect our financial condition and results of operations.


Two pipeline suppliers under firm contracts having expiration dates from 2007 to 2023 transport our natural gas to us. All of these contracts have provisions which allow us to extend the terms ranging from 2020 to 2032. Our electric services are provided by two suppliers under contracts, which expire in 2007 and 2017.


The recent renewal of the electricity supply contract that was terminated in 2006 and the one that will expire in 2007 will result in the cost of electricity more than doubling over existing prices.  Extensions or renewals of our natural gas contracts could result in the cost of natural gas increasing.  Although these increases are currently passed through to our customers, these could have a significant impact on our financial condition and results of operations due to decreased consumption or if costs cannot be passed through in the future.


Fluctuation in prices under long-term purchase and transportation commitments may have an adverse effect on our financial condition and results of operations.


To ensure a reliable supply of electricity and natural gas at competitive prices, we have entered into purchase and transportation contracts with various suppliers and producers, which expire at various dates through 2023. Purchase prices under these contracts are determined by formulas either based on market prices or at fixed prices.


As of December 31, 2006, we have firm purchase and transportation commitments adequate to supply our expected sales requirements for electricity with contracts that will expire in 2017. Our contract in the Northeast division of the electric segment began January 1, 2007 and expires on December 31, 2017. We have a contract with a supplier for the Northwest division beginning January 1, 2008 and expiring December 31, 2017. We are currently seeking approval with the FPSC for the Northwest division contract. If the FPSC does not approve this contract, we may need to seek an alternative supplier or new contract with this same supplier for the purchase of electricity in the Northwest division.


Our natural gas pipeline transportation contracts expire in parts in 2010, 2015 and 2023. We are committed to pay demand or similar fixed charges monthly through 2023 related to the natural gas pipeline transportation agreements. Significant fluctuation in prices under these long-term purchase and transportation commitments may have a material adverse effect on our financial condition and results of operations.


Problems with operations could materially adversely impact us.


We are subject to various operational risks, including accidents, outages, equipment breakdowns or failures, or operations below expected levels of performance or efficiency. Problems such as the breakdown or failure of transmission lines, pipelines or other equipment or processes and interruptions in service which would result in performance below affected levels of output or efficiency, particularly if extending for prolonged periods of time, would have a material adverse effect on our financial condition and results of operations.


We are vulnerable to interest rate changes and may not have access to capital at favorable rates, if at all.


Changes in interest rates can affect our cost of borrowing on our line of credit, on refinancing of debt maturities and on incremental borrowing to fund new investments. Because our stock is not widely held and has a low trading volume, we may not be able to access the equity market or may be limited in the amount of equity financing. If we are unable to obtain equity or debt financing on terms satisfactory to us, our ability to fund capital expenditures and other commitments will be impaired. Moreover, even if available, the cost of such financing could reduce our margins and materially adversely affect our results of operations.


Failure to effectively and efficiently manage our growth, as well as changes in our business strategies, could have a negative impact on our performance.


An essential part of our business strategy is to grow our businesses. Much of our growth depends on our ability to find attractive development opportunities and to obtain the necessary financing for them. Our outlook is based on our expectation that we will be successful in finding and capitalizing on development opportunities, but our efforts may not be successful. Our failure to effectively and efficiently manage our growth, as well as changes in our business strategies, may have a material adverse effect on our financial condition and results of operations. If we grow our business with acquisitions there is a risk the acquisition will not have a positive effect on our financial condition.


Our ability to pay dividends on our common stock is limited.


We cannot guarantee that we will continue to pay dividends at our current annual dividend rate or at all.  In particular, our ability to pay dividends in the future will depend upon, among other things, our future earnings, our cash requirements and our debt covenants.


Provisions in our certificate of reincorporation, certain agreements, and the Florida Business Corporation Act may inhibit a takeover, which could adversely affect the value of our common stock.


Our certificate of reincorporation as well as provisions of the Florida Business Corporation Act (FBCA), contain provisions that could delay or prevent a change of control in our management that shareholders might consider favorable and may prevent them from receiving a takeover premium for their shares.


Our certificate of reincorporation contains provisions that make it more difficult to obtain control of our company through transactions, which have not received the approval of our board of directors.  These provisions include supermajority voting requirements for certain transactions with affiliated persons, staggering the terms of the members of our board of directors, and certain procedural requirements relating to shareholder meetings and amendments to our certificate of reincorporation or bylaws.


In addition, Florida has enacted legislation that may deter or frustrate takeovers of Florida corporations.  Subject to certain exceptions, the "Control Share Acquisitions" section of the FBCA generally provides that shares acquired in excess of certain specified thresholds, beginning at 20% of a corporation’s outstanding voting shares, will not possess any voting rights unless such voting rights are approved by a majority vote of the corporation’s disinterested shareholders.


The "Affiliated Transactions" section of the FBCA generally requires majority approval by disinterested directors or supermajority approval by disinterested shareholders of certain specified transactions (such as mergers, consolidations, sales of assets, issuance or transfer of shares or reclassifications of securities) between a corporation and a holder of more than 10% of the outstanding shares of the corporation, or any affiliate of such shareholder.


Finally, we have agreements with three of our executive officers that provide for significant payments to those executives upon a change in control under certain circumstances. The existence of these contracts may make an acquisition of our company less attractive to a possible buyer.


Conflict or turmoil in oil producing countries could impact future prices for commodities including natural gas, propane gas and electricity, and increases in these prices could materially affect our financial condition and results of operations.


Worldwide turmoil could cause the cost of crude oil and its associated products to rise on concerns of the conflicts interfering with the production of crude oil. If these conflicts are large, escalate or spread, the impact to the cost of all fuel related commodities could increase substantially. These increases could materially adversely affect our financial condition and results of operations.


Item 1B.   Unresolved Staff Comments


None


Item 2.   Properties


We have natural gas, electric and propane gas utility related properties. These properties include transmission, distribution, storage and general facilities at various locations in our service areas. We do not have generating facilities. We maintain property that is adequate for our current operations and we expand our existing facilities as required by growth or other operational needs.


We own natural gas mains that distribute gas through 1,558 miles of pipe located in Central and South Florida. Additionally, we have adequate gate stations in each distribution system.


In the electric segment, we own 22 miles of electric transmission lines located in Northeast Florida and 1,082 miles of electric distribution lines located in Northeast and Northwest Florida. The distribution lines are installed both under and above ground with many of the coastal locations having under ground facilities. All transmission lines are installed above ground. Additionally, we own various substations and regulator stations that are used in our operations.


Our propane gas segment has bulk storage facilities and tank installations on the customers' premises. We also have 16 community gas systems that distribute propane gas to customers in a specific area. These systems are subject to the Federal Department of Transportation Office of Pipeline Safety Regulations.


We own office and warehouse facilities in Northwest, Northeast, Central, West and South Florida, which are used for our operations and materials storage by the natural gas, electric, and propane gas segments.  We also have various easements and other assets located throughout our service areas that are utilized by all of our operations.


We also own a three-story building in West Palm Beach, where our corporate headquarters is located.


All of our property is subject to a lien collateralizing our funded indebtedness under our Mortgage Indenture as discussed in Note 1-I in Notes to Consolidated Financial Statements.


Item 3.   Legal Proceedings


In our operations, we currently use or have used several contamination sites that have pending or threatened environmental litigation. We are in the process of investigating and assessing this litigation.  We intend to vigorously defend our rights in this litigation.  We have insurance and rate relief to cover losses or expenses incurred as a result of this litigation.  We believe all future contamination assessment and remedial costs, legal fees and other related expenses would not exceed the combined sum of any insurance proceeds received and any rate relief granted.


West Palm Beach Site

We are currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property we own in West Palm Beach, Florida. We previously operated a gasification plant at this site. We entered into a Consent Order with the FDEP effective April 8, 1991. This requires us to delineate the extent of soil and groundwater impacts associated with the prior operation of the gasification plant and to remediate such soil and groundwater impacts, if necessary. We have submitted numerous reports to FDEP describing the results of soil and groundwater sampling conducted at the site. We completed the delineation of soil and groundwater impacts at the site in October 2006. An engineering consultant performed a feasibility study to evaluate appropriate remedies for the site. The feasibility study was transmitted to FDEP on November 30, 2006.


The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. The total costs for the remedies evaluated in the feasibility study ranged from a low of $2.8 million to a high of $54.6 million. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, consulting/remediation costs to address the impacts now characterized at the West Palm Beach site are projected to range from $4.6 million to $17.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone (PBZ), monitored natural attenuation of dissolved impacts in groundwater (MNA) or some combination of these remedies. The feasibility study proposed a remedy of superficial soil excavation, and installation of a hanging barrier wall with PBZ and MNA, the cost of which is projected to range from $4.6 million to $9.9 million.


Prior to FDEP's approval of a final remedy for the site, we are unable to determine, to a reasonable degree of certainty, the complete extent or cost of remedial action that may be required. As of December 31, 2006, and subject to the limitations described above, remediation costs (including attorneys' fees and costs) for this site are projected to range from approximately $4.8 million to $18 million.


Sanford Site

We own a parcel of property located in Sanford, Florida, upon which a gasification plant was operated prior to our acquisition of the property. Following discovery of soil and groundwater impacts on the property, we have participated with four former owners and operators of the gasification plant in the funding of numerous investigations of the extent of the impacts and the identification of an appropriate remedy. On or about March 25, 1998, we executed an Administrative Order on Consent (AOC) with the four former owners and operators (Group) and the United States Environmental Protection Agency (EPA) that obligated the Group to implement a Remedial Investigation/Feasibility Study (RI/FS) and to pay EPA's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (WFS Participation Agreement). Work under the RI/FS AOC and RI/FS Participation Agreement is now complete and we have no further obligations under either document.


In late September 2006, EPA sent us a Special Notice Letter, notifying us of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments), and giving the other Group members and us sixty (60) days within which to submit a "good faith offer" to EPA to provide for implementation of the selected remedies. The Special Notice Letter included an Amended Record of Decision (ROD) for OU1 (the ROD for OU1 was amended to account for a significant increase in the volume of off-site soil impacts and a change in the selected remedy), the original ROD for OU2, and a ROD for OU3. The total estimated remediation costs for the Sanford Gasification Plant Site are now projected to be $12.5 million. On November 30, 2006, we, along with the Group, submitted to EPA a good faith offer to implement the approved remedies as set forth in the RODs for OU1 through OU3.


In January, we, along with the other members of the Group signed a Third Participation Agreement, which provides for funding the remediation work specified in the RODs for OU1 through OU3 and supercedes and replaces the Second Participation Agreement. Our share of remediation costs under the Third Participation Agreement is set at 5% of a maximum of $13 million or $650,000.  At present, it is not anticipated that the total cost of remediation will exceed $13 million.  If it does, the Group members have agreed to negotiate in good faith to allocate the excess costs at such time that it reasonably appears that the total remediation costs will exceed $13 million.  In any such event, we do not expect our share of such additional costs to be greater than 5% and our share of such additional costs may be less than 5%.


Our future legal costs and expenses and our share future remediation expenses for this site are currently projected to be approximately $710,000.


Pensacola Site

We are the prior owner/operator of the former Pensacola gasification plant, located in Pensacola, Florida. Following notification on October 5, 1990 that FDEP had determined that we were one of several responsible parties for any environmental impacts associated with the former gasification plant site, we entered into cost sharing agreements with three other responsible parties providing for the funding of certain contamination assessment activities at the site.


Following field investigations performed on behalf of the responsible parties, on July 16, 1997, FDEP approved a final remedy for the site that provides for annual sampling of selected monitoring wells. Such annual sampling has been undertaken at the site since 1998. Our share of these costs is less than $2,000 annually or a total cost of $27,000.


In March 1999, EPA requested site access in order to undertake an Expanded Site Inspection (ESI). The ESI was completed by EPA's contractor in 1999 and an ESI Report was transmitted to us in January 2000. The ESI Report recommends additional work at the site. The responsible parties met with FDEP on February 7, 2000 to discuss EPA's plans for the site. In February 2000, EPA indicated preliminarily that it will defer management of the site to FDEP; however, as of December 31, 2006, we have not received any written confirmation from EPA or FDEP regarding this matter. Prior to receipt of EPA's written determination regarding site management, we are unable to determine whether additional fieldwork or site remediation will be required by EPA and, if so, the scope or costs of such work.


Key West Site

From 1927-1938, we owned and operated a gasification plant in Key West, Florida. The plant discontinued operations in the late 1940s; the property on which the plant was located is currently used for a propane gas distribution business. In March 1993, a Preliminary Contamination Assessment Report (PCAR) was prepared by a consultant jointly retained by the current site owner and us and was delivered to FDEP. The PCAR reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, FDEP notified us that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." FDEP then referred the matter to its Marathon office for consideration of whether additional work would be required by FDEP's district office under Florida law. As of December 31, 2006, we have received no further communication from FDEP with respect to the site. At this time, we are unable to determine whether additional fieldwork will be required by FDEP and, if so, the scope or costs of such work. In 1999, we received an estimate from our consultant that additional costs to assess and remediate the reported impacts would be approximately $166,000. Assuming the current owner shared in such costs according to the allocation agreed upon by the parties for the PCAR, our share would be approximately $83,000.


Item 4.   Submission of Matters to a Vote of Security Holders


None



Executive Officers of the Registrant


The following sets forth certain information about the executive officers of the Company as of February 17, 2007.


 

 

 

 

 

 

 

 

 

 

 

 

Name

Age

Position

Date

 

 

 

 

John T. English

63

Chairman of the Board

2006 - Present

 

 

Chief Executive Officer

1998 - Present

 

 

President

1997 - Present

 

 

Chief Operating Officer

1997 - 2000

 

 

 

 

Charles L. Stein

57

Chief Operating Officer

2001 - Present

 

 

Senior Vice President

1997 - Present

 

 

 

 

George M. Bachman

47

Corporate Secretary

2004 - Present

 

 

Chief Financial Officer

2001 - Present

 

 

Treasurer

2001 - Present

 

 

 

 


Mr. English was Senior Vice President from 1993 preceding his appointment as President and Chief Operating Officer.


Mr. Stein was Vice President from 1993 preceding his appointment as Senior Vice President.


Mr. Bachman was Controller from 1996 preceding his appointment as Chief Financial Officer and Treasurer.


Each of these executive officers has an employment agreement for a three-year term, which can be renewed at the Board Meeting preceding the expiration of the agreement subject to his earlier resignation or removal.  There are no family relationships among any of the executive officers and directors of the Company.


PART II


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


Quarterly Stock Prices and Dividends Paid


Our common shares are traded on the American Stock Exchange under the symbol FPU.  The quarterly dividends declared and the reported last sale price range per share of our common stock for the most recent two years were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

2005

 

Stock Prices

Dividends

 

  Stock Prices *

Dividends

Quarter ended

Low

 

High

Declared

 

Low

 

High

Declared*

March 31 

$13.25 

 

$14.50 

$0.1033 

 

$11.47 

 

$13.49 

$0.1000 

June 30 

11.86 

 

14.40 

0.1075 

 

11.45 

 

12.67 

0.1033 

September 30 

 12.61 

 

14.42 

0.1075 

 

12.67 

 

16.84 

0.1033 

December 31 

13.10 

 

14.05 

0.1075 

 

13.46 

 

16.44 

0.1033 


* On July 25, 2005 we issued a three for two stock split in the form of a stock dividend to our shareholders of record on July 15, 2005. All common share information has been restated to reflect the stock split.


As of February 16, 2007, there were approximately 3,900 holders of record of our common shares.


We intend to continue to pay quarterly cash dividends for the foreseeable future. Our dividend policy is reviewed on an ongoing basis by our Board of Directors and is dependent upon future earnings, cash flow, financial condition, capital requirements and other factors.  Our Fifteenth Supplemental Indenture of Mortgage and Deed of Trust restricts the amount that is available for cash dividends.  At December 31, 2006, approximately $9 million of retained earnings were free of such restriction and therefore available for the payment of dividends.


Securities Authorized for Issuance under Equity Compensation Plans


 

 

 

 

 

 

Equity Compensation Plan Information

 

Plan Category

Number of Securities remaining available for future issuance under equity compensation plans

Equity compensation plans approved by security holders

72,749*

Equity compensation plans not approved by security holders

    -

Total

                           72,749

 

 

* This includes 20,714 shares for the Non-Employee Director Compensation Plan. This plan was adopted by the Board of Directors on March 18, 2005 and was approved at the 2005 meeting of shareholders. This also includes 52,035 shares for the Employee Stock Purchase Plan.



PERFORMANCE GRAPH


The following graph compares the yearly percentage change and the cumulative total of shareholder return on the Company’s common stock with the cumulative return on the Russell 2000 Index (Russell 2000) and Standard & Poor’s Utilities Index (S&P Utilities) for the last five calendar years.  These comparisons assume the investment of $100 in the Company’s common stock and each of the indices on January 1, 2001 and the reinvestment of dividends.  The stock price performance shown in the graph below should not be considered indicative of future stock performance.


[f10k2006002.gif]

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12/01

12/02

12/03

12/04

12/05

12/06

Florida Public Utilities Company

100.00

119.25

131.72

165.01

181.67

182.09

Russell 2000

100.00

79.52

117.09

138.55

144.86

171.47

S & P Utilities

100.00

70.01

88.39

109.85

128.35

155.29

 

 

 

 

 

 

 



Item 6.   Selected Financial Data


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands, except per share data)

Years Ended December 31,

 

2006 

 

2005 

 

2004 

 

2003 

 

2002 

Revenues

$ 

134,393 

$ 

130,023 

$ 

110,039 

$ 

102,723 

$ 

88,461 

 

 

 

 

 

 

 

 

 

 

 

Gross profit

$ 

48,422 

$ 

47,219 

$ 

40,689 

$ 

37,733 

$ 

34,929 

Earnings:

 

 

 

 

 

 

 

 

 

 

Continuing operations

$ 

4,169 

$ 

4,248 

$ 

3,594 

$ 

2,522 

$ 

2,761 

Discontinued operations (1)

 

- 

 

- 

 

- 

 

9,901 

 

602 

Net income

$ 

4,169 

$ 

4,248 

$ 

3,594 

$ 

12,423 

$ 

3,363 

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share (basic and diluted):

 

 

 

 

 

 

 

 

 

 

Continuing operations

$ 

 0.69 

$ 

0.71 

$ 

0.60 

$ 

0.43 

$ 

0.47 

Discontinued operations (1)

 

- 

 

- 

 

- 

 

1.69 

 

0.10 

Total

$ 

0.69 

$ 

0.71 

$ 

0.60 

$ 

2.12 

$ 

0.57 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per common share

$ 

0.43 

$ 

0.41 

$ 

0.40 

$ 

0.39 

$ 

0.38 

 

 

 

 

 

 

 

 

 

 

 

Total assets

$ 

180,913 

$ 

182,666 

$ 

 170,503 

$ 

160,944 

$ 

148,487 

Utility plant – net

$ 

129,211 

$ 

123,061 

$ 

117,191 

$ 

107,942 

$ 

103,357 

Current debt

$ 

3,466 

$ 

9,558 

$ 

5,825 

$ 

2,278 

$ 

19,183 

Long-term debt

$ 

50,702 

$ 

50,620 

$ 

50,538 

$ 

50,454 

$ 

50,367 

Common shareholders' equity

$ 

47,572 

$ 

45,503 

$ 

43,213 

$ 

41,463 

$ 

30,883 


Note to the Selected Financial Data:



(1) On December 3, 2002, FPU entered into an agreement to sell the assets of its water utility system to the City of Fernandina Beach.  The transaction closed on March 27, 2003.  Revenues, Gross profit and Utility plant-net do not include discontinued operations.



Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operation


RESULTS OF OPERATIONS


General

Effects of seasonal weather conditions, the timing of rate increases, fluctuations in demand due to the cost of fuel passed on to customers and the migration of winter residents and tourists to Florida during the winter season all have an impact on income.


Revenues and Gross Profit Summary

Revenues include cost recovery revenues. The FPSC allows cost recovery revenues to directly recover costs of fuel, conservation and revenue-based taxes in our natural gas and electric segments. Revenues collected for these expenses have no effect on results of operations and fluctuations could distort the relationship of revenues between periods. Gross profit is defined as gross operating revenues less fuel, conservation and revenue-based taxes that are passed directly through to customers. Because gross profit eliminates these cost recovery revenues, we believe it provides a more meaningful basis for evaluating utility revenues. The following summary compares gross profit between periods and units sold in One thousand Dekatherm (MDth) (gas) and Megawatt Hour (MWH) (electric).



 

 

 

 

 

 

 

 

Revenues and Gross Profit

(Dollars in thousands)

 

Year Ended December 31,

 

2006

2005

2004

Natural Gas

 

 

 

Revenues

$71,139 

$69,094 

$55,962 

Cost of fuel and other pass through costs

43,909 

42,815 

34,232 

Gross Profit

$27,230 

$26,279 

$21,730 

   Units sold: (MDth)

6,230 

6,224 

 6,124 

Electric

 

 

 

Revenues

$48,527 

$47,450 

$42,910 

Cost of fuel and other pass through costs

34,259 

33,352 

29,732 

Gross Profit

$14,268 

$14,098 

$13,178 

   Units sold: (MWH)

849,124 

814,353 

766,349 

Propane Gas

 

 

 

Revenues

$14,727 

$13,479 

$11,167 

Cost of fuel and other pass through costs

7,803 

6,637 

5,386 

Gross Profit

$ 6,924 

$6,842 

$5,781 

Units sold:  (MDth)

621 

 640 

614 

Consolidated

 

 

 

Revenues

$134,393 

$130,023 

$110,039 

Cost of fuel and other pass through costs

85,971 

82,804 

69,350 

Gross Profit

$ 48,422 

$ 47,219 

$ 40,689 


Natural Gas

Natural gas revenues increased $2.0 million, or 3% in 2006 over 2005 primarily due to increased revenue collected for taxes passed directly through to customers. A change in legislature regarding the calculation of Gross Receipts tax became effective January 1, 2006, and along with an increase to overall revenues, increased these taxes paid by our customers by approximately $500,000.  Franchise fee revenues also increased by approximately $500,000 due to increased rates and area expansion.


Natural gas gross profit increased by $951,000, or 4% in 2006 over 2005. We had higher revenue and gross profit in 2006 compared to 2005 primarily due to billed revenue not exceeding the FPSC allowable earnings as much as in the prior year. In 2006, we reduced billed revenues and gross profit by our estimate of over-earnings of $72,000 for the year. Our estimate for 2005 was recorded at $700,000 in 2005 and we reduced that estimate in 2006 by $50,000 to $650,000. The combined effect of this was to increase our revenues and gross profit over the prior year by approximately $678,000. Other factors contributing to the increase in revenues and gross profit were 2% customer growth and storm surcharge revenues, which became effective November 2005. The revenues and gross profit increases were slightly offset by the loss of approximately $100,000 of revenue from two customers who went off-line for several months to do maintenance work.


Natural gas revenues increased $13.1 million in 2005 over 2004 primarily due to an $8.6 million increase in the cost of fuel and other costs that were passed through to customers. The cost of natural gas increased significantly over prior years, partially as a result of hurricanes and their impact on supplies. Gross profit increased $4.5 million, or 21%, primarily as a result of rate relief effective in November 2004, normal customer growth and a 2% increase in units sold. Offsetting these increases was the estimated over-earnings for 2005 of $700,000, which reduced revenues and gross profit.


Electric

Electric revenues increased $1.1 million in 2006 over 2005.  Cost of fuel and other costs that were passed through to customers contributed approximately $900,000 of the increase. Gross profit increased $170,000 or 1% in 2006 over 2005.  The increase in gross profit was primarily due to a slight increase in customer growth and units sold.


Electric revenues increased $4.5 million in 2005 over 2004.  Cost of fuel and other costs that were passed through to customers contributed $3.6 million of the increase. Gross profit increased $920,000 or 7% in 2005 over 2004.  The increase in gross profit was primarily due to a 6% increase in units sold along with the rate increases granted in March 2004. A large distribution center was built in our Northwest division and increased revenues by approximately $700,000 and gross profit by approximately $91,000 in 2005 over 2004.


Propane Gas

Propane revenues increased $1.2 million, or 9% and gross profit increased $82,000 or 1% in 2006 compared to 2005.  Revenues increased primarily due to rising fuel costs.  Although customers increased by 5% in 2006, the usage per customer declined by 8% contributing to a decrease of 3% in units sold.  Warmer weather was the primary reason for this decrease in usage per customer in 2006 compared to 2005. The increase in gross profit was minimal when compared to last year primarily due to pre-buy gains of $383,000 realized in 2005 but not in 2006.


Propane revenues increased $2.3 million and gross profit increased $1.1 million or 18% in 2005 compared to 2004.  The Company realized gains of approximately $383,000 as a result of buying propane supplies before market price increases. The remaining increase of 12% from the previous year resulted from propane unit sales increasing 4% due primarily to a 13% growth in residential bulk customers and units sold.


Operating Expenses

Operating expenses include operation, maintenance, depreciation, amortization and taxes other than income taxes, and exclude fuel costs, conservation and taxes based on revenues that are directly passed through to customers and recovered in revenues.


 

 

 

 

 

 

 

 

Operating Expenses

(Dollars in thousands)

 

Year Ended December 31,

 

2006 

2005

2004

Natural gas

$   21,112 

$   20,230 

$   16,752 

Electric

11,215 

   10,596 

     9,825 

Propane gas

5,918 

     5,756 

     5,126 

Total Operating Expenses

$ 38,245 

 $   36,582 

 $   31,703 


Natural Gas

Natural gas operating expenses increased $882,000, or 4%, in 2006 as compared with 2005. Outside of the normal inflationary impacts on our expenses, customer account expenses increased by $237,000 as a result of our customer service focus initiated in 2005 based on our strategic plan. We continued the focus on this area and increased the number of employees in an effort to respond more effectively to customers.  Bad debt provision increased $49,000 over the prior year primarily due to increasing revenues, aging accounts receivable on several major accounts, and the slowing housing economy. We increased our collection efforts in the fourth quarter of 2006 and will continue to do so in 2007.


In 2006 we had additional increases of $90,000 to sales expense resulting from initiatives to boost sales by increasing sales staff. Depreciation expense increased $137,000 principally due to construction of mains and new meters to distribute gas to a growing number of new developments in South Florida and increasing capacity requirements for existing customers.


Natural gas operating expenses increased $3.5 million or 21%, in 2005 as compared with 2004. Amortization expense increased $1 million. The bare steel replacement program and recovery of future environmental costs approved in our 2004 natural gas rate proceeding were the primary reasons for this increase. We are currently under a 50-year program to replace all bare steel mains and service lines with coated steel and polyethylene lines. We have received approval to recover the funds necessary to replace these mains and services over the 50-year period. Pursuant to an FPSC mandate, we accrue an amortization expense as an offset to the revenues received, and record a contribution reducing the related construction expenditures. The FPSC also approved recovery of our expected environmental liability over a 20-year period.


Customer account expense increased $373,000 in 2005 as compared to 2004 primarily due to increased payroll expenses for additional staffing and facility and equipment upgrades. There were also increased bad debt provisions as a result of the increases in accounts receivable due to general and fuel rate increases.  The purchase of additional safety equipment, tools, hardware and office furniture contributed to a $942,000 increase in other operating expense. Other items affecting expenses included a research marketing study to provide us with data to better serve our customers and additional payroll expenses relating to hurricane preparedness and wage increases. Maintenance expense increased by $208,000 primarily due to maintenance expenditures in Central Florida for cleaning and painting a distribution regulator and gate stations and the purchase of maintenance related safety equipment and tools.


Electric

Electric operating expenses increased $619,000, or 6%, in 2006 as compared with 2005.  As a result of our efforts to inform and educate our electric customers about the expected 2007 and 2008 fuel rate increases in upcoming bills, sales expense increased by $120,000. Customer account expenses increased $106,000 in 2006 over the prior year mainly due to increased bad debt provisions due to higher sales and slower housing economy. Depreciation expense increased $202,000 largely due to major construction work done in the latter part of 2005 and the beginning of 2006. This included the rebuilding of a transmission sub-station, the rebuilding of an entire distribution sub-station with two transformers and the replacement of a failed sub-distribution station transformer. Additional significant work on transformers is expected in 2008.


Electric operating expenses increased $771,000, or 8%, in 2005 as compared with 2004.  As we continued to focus on improving service reliability, we increased maintenance expense by $397,000 for additional tree trimming and the use of a temporary mobile substation while a new transformer was purchased and put into service. Depreciation expense increased $100,000 due to normal increases in plant assets. In 2005, other operating expenses increased $114,000 due to a shift from work on capital assets to operational needs along with personnel raises.


Propane Gas

Propane gas operating expenses increased $162,000, or 3%, in 2006 as compared with 2005. Depreciation expense increased $99,000 for the addition of plant assets including a propane gas delivery system that will increase the efficiency of our deliveries and improve our overall customer satisfaction. Aging accounts receivable, slowing housing economy and increasing revenues contributed to an increase in our bad debt expense over the prior year.


Propane gas operating expenses increased $630,000, or 12%, in 2005 as compared with 2004. As we continued to focus on increasing our propane gas business, other operating costs increased $467,000. We placed additional emphasis in the sales area, which resulted in signing up new housing developments that will utilize propane gas. We incurred increased expenditures for piping homes, delivering propane gas, implementing a new delivery system and increasing commission payments. This increased effort in our sales area contributed to an increase of 150 customers and 4% overall units sold in our propane gas segment.


Administrative Expenses

Administrative expenses increased $487,000, or 6%, in 2006 over 2005. These expenses generally are related to all of our operating segments. To continue to adequately support our internal and external customers, we increased staffing in our administrative areas. Payroll increases of $322,000 related to an increased number of employees, annual pay raises and normal inflationary impacts.  In 2006, we discontinued eligibility to our defined benefit pension plan for new employees and replaced the defined benefit pension plan with a 401K-match plan for new employees. This change will take time to reduce pension expense; we had an increase of $203,000 in our pension expenses in 2006.  Medical costs increased $120,000 over the prior year and these costs are expected to continue to rise.


Regulatory storm surcharge expenses approved in our 2005 natural gas petition increased natural gas expenses by $180,000.


Administrative expenses increased $996,000, or 13%, in 2005 over 2004.  Pension expense increased $274,000 due to our estimate that the return on the pension’s assets will not keep pace with growing pension liabilities.  Medical insurance premiums continue to rise, increasing $130,000 in 2005. Compliance costs related to Sarbanes-Oxley and internal control requirements, as well as audit fees, increased outside services expenses by $156,000. With the impact from our focus on hurricane preparations and the 2005 hurricanes, our safety expense increased by $235,000. A portion of this increase related to compensation for an additional safety employee and costs for a new safety incentive program.


Total Other Income and Deductions

Other income and deductions include revenues and expenses from sales and installation, service of merchandise, gains or losses on disposal of property, interest expense and other income and expenses. The largest components of this section are merchandise sales, services income and interest expenses. Our service activities include the installation of merchandise and other contract work. Interest expense consists of interest on bonds, short-term borrowings and customer deposits.


Merchandise and Services Revenue and Expenses

Although merchandise and services revenue decreased by approximately $268,000 in 2006, the overall profitability in this area increased by $325,000 compared to 2005. This was primarily a result of significant strategic changes made by management. These changes included revising the product markup structure, increasing installation fees and increasing employee training. We experienced a revenue decrease due to lower demand for merchandise as a result of a quiet hurricane season and the slow down of new construction projects in our areas due to the downturn in the housing market.


Merchandise and services revenues and expenses increased in 2005 from 2004 but profitability decreased $114,000. We experienced an increase in revenues and cost of sales primarily due to an increased demand for electric to gas conversions and installations of customer owned propane gas tanks to supply back-up generators. We had increased expenses from sub-contractors that were not passed on to customers in sales prices.


Interest Expenses

In 2005, total interest expense increased $106,000. Interest on short-term debt increased $37,000. This was due to the increase in the average outstanding loan balance on the line of credit and higher interest rates.  Interest on customer deposits increased $48,000 due to increased customer deposits primarily as a result of additional deposits required after implementing increased rates in our natural gas operation.


Other

Other revenues increased $51,000 compared to 2005 due to additional interest income associated with the sale of the water assets.


Income Taxes

Income tax expense decreased in 2006 over the normal tax rate on net income by $67,000. This decrease was due to tax return adjustments related to the regulatory deferred tax liabilities.


Income tax expense decreased in 2005 over the normal tax rate on net income by $43,000. Tax return adjustments related to the sale of our water assets and the regulatory deferred tax liabilities decreased expenses by $118,000. We had an offsetting increase of $75,000 related to our IRS audit of the 2002 and 2003 income tax returns.


Liquidity and Capital Resources


 

 

 

 

 

 

 

 

 

 

 

 

Summary of Primary Sources and Uses of Cash

(Dollars in thousands)

 

Year Ended December 31,

 

2006 

2005

2004

Sources of Cash:

 

 

 

Operating activities, including working capital changes

$20,090 

$10,213 

$11,673 

Net proceeds on short-term debt

- 

3,733 

3,547 

Other sources of cash

1,179 

1,214 

648 

Uses of Cash:

 

 

 

Construction expenditures

13,116 

12,441 

13,731 

Dividends paid

2,551 

2,448 

2,368 

Net payment on short-term debt

6,092 

- 

- 

Other uses of cash

121 

75 

129 

     Net (use) source of cash

$ (611)

$    196 

$   (360)


Cash Flows

Operating Activities

Net cash flow provided by continuing operating activities increased in 2006 by approximately $10 million compared to 2005.  Fuel and other pass through costs accounted for $6.5 million of the increase. This increase resulted from the collection of the prior year's under-recoveries of $3.4 million and over-recoveries of $3.1 million in 2006.  Amounts over-recovered will be refunded to customers in subsequent calendar years.  Lower fuel costs during the latter part of the year in our natural gas segment contributed to a decrease in receivables and increase in cash of $3 million.  The lower fuel costs and timing of payments to our major fuel suppliers resulted in a decrease to operating cash of $1 million.  Income taxes paid increased by approximately $600,000 primarily due to the tax effect of the collection of prior year’s fuel under-recoveries.


Net cash flow provided by continuing operating activities decreased in 2005 by approximately $1.5 million compared to 2004. Payments for fuel exceeded the amount collected from customers by an additional $3.1 million in 2005. The under-recovery of fuel costs is collected in the following calendar year. Income tax payments increased approximately $1.5 million, primarily as a result of less tax depreciation and higher income.  The deduction for tax depreciation was higher in 2004 as a result of bonus depreciation, resulting in lower taxes in that year.  We also received a refund in 2004 relating to the deferral of the gain on our water assets sale.


Offsetting the decreases to 2005 cash flow was additional cash received from rate increases in our natural gas segment. The rate increases also contributed to an increase to accounts receivable of $4 million.  Accounts payable increased $3.3 million in 2005 primarily due to the increased cost of fuel in our natural gas segment.


Investing Activities

Capital expenditures increased in 2006 compared to 2005 by approximately $700,000. The increase in 2006 included expenditures for transportation equipment in our electric segment for approximately $400,000, vehicles in our natural gas segment above 2005 levels of approximately $600,000, and various other typical capital expenditures. Offsetting total 2006 increases was a $663,000 transformer replacement in 2005.


Capital expenditures decreased in 2005 compared to 2004 by approximately $1.3 million. In 2004, there were large projects to rebuild two substations in our electric segment and additional propane community gas systems costing approximately $3.3 million. In 2005 such expenditures were lower and consisted of the purchase of a transformer in our electric segment for $663,000, a new natural gas mapping system to track our assets used in serving our customers for approximately $300,000, a propane delivery system for approximately $300,000, additional propane community gas systems for approximately $300,000 and other various capital expenditures.


Financing Activities

Short-term borrowings decreased by $6 million in 2006. Over-recovery of fuel costs provided a large source of cash during 2006 as well as the recovery of the prior year’s under-recovery of fuel costs in 2006, reducing the need for short-term borrowings.


Although additional sources of cash were provided by our rate increases and lower construction expenditures in 2005, the additional expenditures from the under-recovery of fuel costs and additional income taxes increased our short-term debt. Short-term borrowings increased in 2005 over 2004 by approximately $3.7 million.


Capital Resources

We currently have a $12 million line of credit, which expires on July 1, 2008. Upon 30 days notice by us we can increase the line of credit to a maximum of $20 million.  The line of credit contains affirmative and negative covenants that, if violated, would give the bank the right to accelerate the due date of the loan to be immediately payable. The covenants include certain financial ratios.  All ratios are currently met and management believes we are in full compliance with all covenants and anticipates continued compliance.  We reserve $1 million of the line of credit to cover expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane gas facilities. As of December 31, 2006, the amount borrowed on the line of credit was $3.5 million. The line of credit, long-term debt and preferred stock as of December 31, 2006 comprised 54% of total capitalization and debt.


In prior years we periodically paid off short-term borrowings under lines of credit using the net proceeds from the sale of long-term debt or equity securities.  We may use similar types of proceeds in the future to pay off short-term borrowings, dependent on the amount borrowed from the line of credit, prevailing market conditions for debt and equity, the impact to our financial covenants and the effect on income.


Our 1942 Indenture of Mortgage and Deed of Trust, which is a mortgage on all real and personal property, permits the issuance of additional bonds based upon a calculation of unencumbered net real and personal property.  At December 31, 2006, such calculation would permit the issuance of approximately $39.3 million of additional bonds.


On November 30, 2006 we received approval from the FPSC to issue and sell or exchange an additional amount of $45 million in any combination of long-term debt, short-term notes and equity securities and/or to assume liabilities or obligations as guarantor, endorser or surety during calendar year 2007. We will seek approval from the FPSC in 2007 for any possible financing in 2008.


We have $3.4 million in invested funds for payment of future environmental costs. We expect to use some of these funds in 2007.


Capital Requirements

Portions of our business are seasonal and dependent upon weather conditions in Florida.  This factor affects the sale of electricity and gas and impacts the cash provided by operations. Construction costs also impact cash requirements throughout the year.  Cash needs for operations and construction are met partially through short-term borrowings from our line of credit.


Capital expenditures are expected to be higher in 2007 compared to 2006 by approximately $3.9 million. The primary reason for the expected increase in expenditures is the anticipated purchase of land for a new South Florida division office. The current division office is on environmentally impacted property, which requires relocating the office to allow for clean up of the property. It is not possible to rebuild at the current location since the property has been rezoned with a residential designation. The estimated cost of land is $3.8 million.  We are planning to build and complete this new facility in the next five years. We do not have any commitments for capital expenditures in 2007 other than vehicles of approximately $102,000.


Cash requirements will increase significantly in the future due to environmental clean up costs, sinking fund payments on long-term debt and pension contributions. Environmental clean up is forecast to require payments of approximately $600,000 in 2007, with remaining payments, which could total approximately $13.1 million, beginning in 2008. Annual long-term debt sinking fund payments of approximately $1.4 million will begin in 2008 and will continue for eleven years. Based on current projections, we will make voluntary contributions in our defined benefit pension plan of $250,000 in 2007 and $500,000 in 2008. Required contributions will begin in 2009 and are forecast to be approximately $2 million in 2009 and 2010.


Based on our current expectations for cash needs, including the possible land purchase and related South Florida office construction, we may choose to consider an equity or debt financing in 2008 to address those cash needs.  The need and timing will depend upon operational requirements, environmental expenditures, pension contributions and construction expenditures and cannot be precisely predicted at this time.  In addition, if we experience significant environmental expenditures in the next two or three years it is possible we may need to raise additional funds.  If interest rates remain favorable we may consider re-financing one of our mortgage bonds. If refinancing is deemed beneficial, we may re-issue the bond for additional principal.  There can be no assurance, however, that equity or debt transaction financing will be available on favorable terms or at all when we make the decision to proceed with a financing transaction.


Outlook


Pension and Insurance Expenses

Insurance costs have been increasing and are expected to continue to increase while we expect pension costs to decrease.  Pension expenses increased $203,000 in 2006 and our actuarial estimates show pension expense increasing by an additional $90,000 in 2007.  Insurance expenses including Medical, Liability and Workers’ Compensation increased $70,000 in 2006 and are expected to increase further in 2007.


The regulated segments received rate relief for some of the historical pension and insurance increases in 2003 and 2004.  Increases beyond those experienced through 2005, which are allocated to the regulated segments, may require requesting future rate relief.  The propane gas segment may recover these expenses by increasing rates, depending on market conditions in the propane gas industry and the ability to remain competitive.


In an effort to keep pension expenses low, we discontinued eligibility to our pension plan for all new hires.


For new hires not eligible for the defined benefit pension plan, we established an employer match to the employee’s contribution to their 401K plans. It provided for a company match of 50% for each dollar contributed by the employee, up to 6% of their salary, for a company contribution of up to 3%. Beginning in 2007, for non-union employees the plan was enhanced to provide a company match of 100% for the first 2% of an employee’s contribution, and a match of 50% for the next 4% of an employee’s contribution, for a total company match of up to 4%. This new enhanced match will be negotiated with our six union contracts during 2007, to be effective on their respective contract date within 2007. The employees are eligible for the company match after six months of continuous service, with vesting of 100% after three years of continuous service.


Electric Power Supply Contracts

Contracts with our two electric suppliers were originally set to expire on December 31, 2007.  Those contracts provided electricity to our customers at rates much lower than market rates.  As part of our negotiations, we agreed to end the current contract terms for our Northeast division on December 31, 2006 and executed an amended contract to begin January 1, 2007 and expire December 31, 2017.  Although the contract rates will increase for 2007, this enabled us to obtain lower rates for the longer term of the contract than would have been available if we had not revised the contract.  The savings are passed through to our customers without profit to us.


We executed a contract for the provider of electricity in our Northwest division in December 2006 and are seeking approval of this contract and its related terms and conditions from the FPSC on or before July 1, 2007. If the FPSC does not approve this contract, we may need to seek an alternative supplier or new contract with this same supplier for the purchase of electricity in the Northwest division.  This contract will be for the purchase of electricity beginning January 1, 2008.  We anticipate that contract will result in rates closer to market, which could cause our customers’ bills to double over existing prices in the next several years.


We are unable to estimate what impact, if any, the higher rates could have on electric consumption.


Propane Gas

We are currently reviewing the possibility of hedging activities in 2007 to help mitigate the risk of price changes for our cost of propane gas. We are unable to determine the impact this activity will have on our future operating income.


We used advance purchase agreements made in the normal course of procuring propane gas supplies in past years. These agreements resulted in a loss of gross profit of approximately $5,000 in 2006 and additional gross profit of approximately $383,000 in 2005 and $242,000 in 2004.


Over-earnings-Natural Gas Segment

The FPSC approves rates that are intended to permit a specified rate of return on investment and limits the maximum amount of earnings of regulated operations. We currently estimate over-earnings in 2006 of $72,000 and in 2005 of $650,000. We revised our prior year’s 2005 estimate of $700,000 during 2006. These liabilities have been included in an over-earnings liability on our balance sheet, with the potential of rate refunds to customers. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations.


Our 2005 and 2006 estimates of our over-earnings liabilities could change upon the FPSC finalization and review of our earnings in 2007 and 2008. The FPSC determines the disposition of over-earnings with alternatives that include refunding to customers, funding storm damage or environmental reserves, or reducing any depreciation reserve deficiency.


In 2007, we requested that the 2005 natural gas over-earnings be used to provide additional funds to our regulatory storm reserve liability and reduce the costs currently being recovered from our customers through a storm surcharge. If the FPSC approves this disposition, we will end the storm surcharge in 2007.

 

Electric Customers

A large commercial customer in our electric division closed its operations in late 2006. As a result we anticipate annual revenues to be reduced by approximately $300,000 and annual gross profit to be reduced by approximately $50,000.


A large distribution center was built in our Northwest division in 2004 and a second facility was added in 2006. A third distribution facility is expected to be added by the end of 2007. Additional industrial and commercial development is planned for this general area, which should increase load significantly. Additional gross profit is anticipated in the future to increase between $30,000 and $50,000 as a result of the additional developments.


Natural Gas Customers

Two natural gas customers went off-line for approximately six months in 2006 due to lower production, market slow down and maintenance work on their facilities.  We anticipate that they will not be fully operational until mid-2007.  The decreased revenue and gross profit is estimated to be $100,000 in 2007.


Indiantown Gas Agreement

The FPSC approved our joint transportation and territorial agreements with Indiantown Gas Company in October 2006. We began construction in the Indiantown area to install natural gas mains in the first phase of this development, for approximately 100 homes. Two more developments are slated for construction of approximately 1,000 homes in 2007.


Storm Preparedness Expenses

Regulators continue to focus on hurricane preparedness and storm recovery issues for utility companies. Newly mandated storm preparedness initiatives could impact our operating expenses and capital expenditures beginning in 2007. The initial forecasts of these annual expenditures are approximately $700,000. It is possible that additional regulation and rules will be mandated regarding storm related expenditures over the next several years. We requested that the FPSC allow us to recover the cost of the newly mandated storm preparedness initiatives and to defer these storm-related expenditures until we receive recovery through a rate increase.  If approved, both the recovery and expenditures may occur by mid-2007. If the FPSC does not approve our request, we plan to file a rate proceeding in 2007 as an alternative option for recovery of these expenditures.


Land Purchase

We are currently reviewing multiple sites for the new South Florida division office. We expect to purchase land for the new South Florida division office during 2007.


Contractual Obligations


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table of Contractual Obligations

(Dollars in thousands)

Payments due by period:

   Total

Less than

    1 year

1 to 3 years

  3 to 5 years

More than

   5 years

Long-term Debt Obligations

$52,500 

$          - 

$2,818 

$2,818 

$46,864 

Long-term Debt Interest

63,904 

3,949 

7,623 

7,074 

45,258 

Operating Lease Obligations

362 

161 

163 

38 

             - 

Natural Gas and Propane Gas Purchase Obligations

64,904 

37,768 

16,244 

4,568 

6,324 

Electric Purchase Obligations

268 

53 

106 

61 

           48 

Other Purchase Obligations

2,698 

922 

1,698 

21 

           57 

Total

$184,636 

$42,853 

$28,652 

$14,580 

$98,551 


Long-term Debt Obligations

The Long-term debt obligations are principal amounts.


Long-term Debt Interest

The Long-term debt interest represents the interest obligation on our Mortgage Bonds.


Operating Lease Obligations

Our total operating lease obligation is $362,000. We are leasing property from the City of Fernandina Beach in our Northeast division. The total obligation for the duration of this lease is about $107,000 over the next five years. We lease our appliance showroom in the same division for approximately $35,000 annually. We also have other operating lease agreements with various terms and expiration dates.


Purchase Obligations

A purchase order is considered an obligation if it is associated with a contract or is authorizing a specific purchase of material. The Other Purchase Obligation amount presented above represents the amount of open orders.


Pension, Medical Postretirement and Other Obligations

Our pension plan continues to meet all funding requirements under ERISA regulations; however, under current actuarial assumptions, contributions may be required as early as 2009.  Current projections indicate that we will make voluntary contributions of $250,000 in 2007, $500,000 in 2008 and make required contributions of approximately $2 million in 2009 and 2010, decreasing to under $1 million in 2011. These payments are not included in the Contractual Obligations table.


Environmental clean up is anticipated to require approximately $600,000 in 2007, the remainder to be paid in following years. These payments are not included in the Contractual Obligations table.


We have medical postretirement payments relating to retiree medical insurance. These payments are not included in the Contractual Obligations table. Estimated future payments are described in Note 12 in the Notes to Consolidated Financial Statements.


Dividends

We have historically paid dividends. It is our intent to continue to pay quarterly dividends for the foreseeable future.  Our dividend policy is reviewed on an ongoing basis by our Board of Directors and is dependent upon our future earnings, cash flow, financial condition, capital requirements and other factors.


Other


Impact of Recent Accounting Standards


Financial Accounting Standard Board Interpretation No. 48

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48).  The interpretation clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes.  The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.  This interpretation is effective for calendar years beginning January 1, 2007.

 

We have performed an analysis of tax positions taken and expected to be taken on the tax returns and assessed the technical merits of each tax position by relying on legislation, statutes, common legislative intent, regulations, rulings, and case law and determined that the Company has no material uncertain tax positions.   Additionally, the IRS concluded an audit of the 2002 and 2003 tax years in September of 2005.


In February of 2007, the IRS informed us that it selected our 2003 and 2004 tax years for examination.  As our tax positions have remained consistent with those from the previously audited tax years, we are not expecting any material adverse findings as the result of the impending IRS audit.

 

Based on the aforementioned, we believe that the adoption of FASB Interpretation No. 48 will not have a material impact on our financial condition or results of operations.


Financial Accounting Standard No. 157

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements”.  This Statement clarifies fair value as the market value received to sell an asset or paid to transfer a liability, that is, the exit value, and applies to any assets or liabilities that require recurring determination of fair value.  The measurement includes any applicable risk factors and does not include any adjustment for volume.  This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within. The Company expects to adopt SFAS No. 157 effective January 1, 2008. The Company does not believe adoption of this Statement will have a material impact on our financial condition or results of operation.


Financial Accounting Standard No. 158

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”. Statement 158 requires the Company to show the funded status of its pension and retiree health care plans as a prepaid asset or accrued liability, and to show the net deferred and unrecognized gains and losses related to the retirement plans, net of tax, as part of accumulated other comprehensive income in shareholders’ equity.  Previously, the net deferred and unrecognized gains and losses were netted in the prepaid asset or accrued liability recorded for the retirement plans. The Company adopted the recognition provisions of Statement 158, as required, at December 31, 2006.


The Company uses December 31 as the measurement date to measure the assets and obligations of its retirement plans.  Statement 158 will also require the Company to use December 31 as the measurement date no later than fiscal years ending after December 15, 2008.  The Company currently uses this date as the measurement date, and has used it for all periods presented.


The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 at December 31, 2006 resulted in an additional liability for retirement plans. The tax on the non-regulated portion of the liability has been recorded as a deferred income tax asset. As an offset, the regulatory portion of this liability has been deferred as a regulatory asset-retirement plans to be recovered in future rate proceedings and the remaining expense for recording the liability has been included in other comprehensive income.  The fair value of retirement plan assets and obligations are subject to change based on market fluctuations. The table below summarizes the effects to our financial statements.


 

 

 

 

 

 

 

 

FASB 158 Implementation Summary

(Dollars in thousands)

 

December 31, 2006

 

Before Application of SFAS 158

Adjustment

After Application of SFAS 158

Assets:

 

 

 

Other regulatory assets- retirement plans

$           - 

$587 

$587 

 

 

 

 

Liabilities and Equity:

 

 

 

Accumulated other comprehensive income/(loss)

- 

(103)

(103)

Other accruals and payables

2,034 

151 

2,185 

Long term medical and pension reserve

4,129 

602 

4,731 

Deferred income taxes

16,167 

(63)

16,104 


Staff Accounting Bulletin No. 108

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108 “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”.  SAB 108 requires that public companies utilize a “dual-approach” to assessing the quantitative effects of financial misstatements.  This dual approach includes an assessment from both an income statement and a balance sheet focus.  The guidance in SAB 108 must be applied to annual financial statements for fiscal years ending after November 15, 2006.  The Company has adopted SAB No.108 and there has not been any impact on our consolidated financial position or results of operations as the result of this adoption.


Critical Accounting Policies and Estimates


Regulatory Accounting

We prepare our financial statements in accordance with the provisions of SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" and it is our most critical accounting policy.  In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the relationship of costs and revenues introduced by rate regulation.  As a result, a regulated utility may defer recognition of a cost (a regulatory asset) or recognize an obligation (a regulatory liability) if it is probable that, through the rate making process, there will be a corresponding increase or decrease in revenues or expenses.  SFAS No. 71 does not apply to our unregulated propane gas operations.

 

Use of Estimates

We are required to use estimates in preparing our financial statements so they will be in compliance with accounting principles generally accepted in the United States of America. Actual results could differ from these estimates. We believe that the accruals for potential liabilities are adequate. The estimates in our financial statements included the accrual for pensions, environmental liabilities, over-earnings liability, unbilled revenues, allowances for doubtful accounts, uninsured liability claims and the regulatory deferred income tax and deferred income tax liabilities.


·

Pension and post retirement benefits-An actuary calculates the estimated pension liability in accordance with FASB 87, FASB 88 as amended by FASB 132 and FASB 158.

·

Environmental liabilities-These liabilities are subject to certain unknown future events. The Company reviews the environmental issues regularly with the geologists performing the feasibility studies and their legal counsel specializing in manufactured gas plant issues and negotiates with the environmental regulators and the other participating parties to determine the adequacy of the estimated liability for environmental reserves.

·

Over-earnings liability-This liability is subject to regulatory review and possible disallowance of some expenses in determining the amount of over-earnings.

·

Unbilled revenues-Unbilled revenue is estimated with certain assumptions including unaccounted for units and the use of current month sales to estimate unbilled sales.

·

Allowances for doubtful accounts- This liability is estimated based on historical information and trended current economic conditions, certain assumptions, and is subject to unknown future events. Actual results could differ from our estimates.

·

Uninsured liability claims-We are self-insured for the first $250,000 of each general and auto liability claim and accrue for estimated losses occurring from both asserted and unasserted claims.  The estimate for unasserted claims arising from unreported incidents is based on an analysis of historical claims data and judgment.  

·

Regulatory deferred income tax and deferred income tax liabilities-These liabilities are estimated based on historical data and are subject to finalization of our income tax return. Actual results could differ from our estimates.


Revenue Recognition

We bill utility customers on a monthly cycle basis; however, the billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting.  We accrue estimated revenue for gas and electric customers for consumption used but not yet billed for in an accounting period.  Determination of unbilled revenue relies on the use of estimates and historical data. We believe that the estimates for unbilled revenue materially reflect the unbilled gross profit for our customers for units used but not yet billed in the current period.


The FPSC approves rates that are intended to permit a specified rate of return on investment and limits the maximum amount of earnings of regulated operations. Any earnings in excess of this maximum amount are accrued for as an over-earnings liability and revenues are reduced for this same amount. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations. The FPSC determines the disposition of any over-earnings with alternatives that include refunding to customers, funding storm damage or environmental reserves or reducing any depreciation reserve deficiency.


Effects of Inflation

Our tariffs for natural gas and electric operations provide for fuel clauses that adjust annually for changes in the cost of fuel.  Increases in other utility costs and expenses not offset by increases in revenues or reductions in other expenses could have an adverse effect on earnings due to the time lag associated with obtaining regulatory approval to recover such increased costs and expenses, the uncertainty of whether regulatory commissions will allow full recovery of such increased costs and expenses and any effect on unregulated propane gas operations.


Environmental Matters

We currently use or have used in the past, several contamination sites that are currently involved in pending or threatened environmental litigation as discussed in Note 10- "Contingen­cies" in the Notes to Consolidated Financial Statements.  We intend to vigorously defend our rights in this litigation.  We have insurance and rate relief to cover any expected losses or expenses. We believe that the aggregate of all future contamination assessment and remedial costs, legal fees and other related expenses would not exceed the insurance proceeds received and any rate relief granted.  The final 2004 natural gas rate relief granted by the FPSC provided future recovery of $8.9 million for environmental liabilities. The remaining balance to be recovered from customers through future recovery is included on the balance sheet as “Other regulatory assets-environmental”.


Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.


Forward-Looking Statements (Cautionary Statement)

This report contains forward-looking statements including those relating to the following expectations:


·

Based on our current expectations for cash needs, including cash needs relating to the possible land purchase and related construction, we may choose to consider an equity or debt financing in 2008 to address those cash needs.  The need and timing will depend upon operational requirements, environmental expenditures, pension contributions and construction expenditures and cannot be precisely predicted at this time.

·

Other insurance costs will increase in 2007.

·

Our anticipation of continued compliance in the foreseeable future with our line of credit covenants.

·

Our expectation that cash requirements will increase significantly in the future due to environmental clean-up costs, sinking fund payment on long-term debt and pension contributions.

·

Electric storm related expenditures may be necessary beginning in mid-2007 and the total cost may be significant. We may receive recovery for these expenditures.

·

Propane gas hedging activity may occur in 2007.

·

The fuel supply contract in our Northwest Florida division beginning January 1, 2008 will be approved by the FPSC in 2007 and will be effective for the purchase of fuel supply beginning in 2008.

·

Our 2005 and 2006 over-earnings liabilities in natural gas will materialize as estimated after the FPSC reviews and audits.

·

We expect to have higher fuel costs for 2007, 2008 and beyond.

·

The development in Indiantown will occur as estimated.

·

The purchase of land for our new natural gas and propane gas division office will occur in 2007.

·

Pension expenses are expected to increase in 2007.

·

The FPSC will allow our natural gas over-earnings to fund a future storm reserve and reduce our current regulatory asset related to historic storm costs and discontinue the related natural gas storm surcharge in 2007.

·

The commercial and industrial growth will occur as expected in our Northwest division providing increases in our revenues and gross profit.

·

The two customers that went off-line in 2006 will be fully operational by mid-2007.


These statements involve certain risks and uncertainties.  Actual results may differ materially from what is expressed in such forward-looking statements.  Important factors that could cause actual results to differ materially from those expressed by the forward-looking statements include, but are not limited to, those set forth above in “Risk Factors”.


Item 7A.  Quantitative and Qualitative Disclosures about Market Risk


All financial instruments held by us were entered into for purposes other than for trading. We have market risk exposure only from the potential loss in fair value resulting from changes in interest rates.  We have no material exposure relating to commodity prices because under our regulatory segments, we are currently fully compensated for the actual costs of commodities (natural gas and electricity) used in our operations.  Any commodity price increases for propane gas are normally passed through monthly to propane gas customers as the fuel charge portion of their rate.


None of our gas or electric contracts are accounted for using the fair value method of accounting.  While some of our contracts meet the definition of a derivative, we have designated these contracts as "normal purchases and sales" under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities".


Beginning in 2007 we plan, on a rolling four-quarter basis, to purchase a “cap” on approximately one-third of our forecast propane gas volume purchases and pre-buy or hedge with a swap one-third of our forecast anticipated propane gas purchases. The remaining one-third will fluctuate with the market price. Our energy strategy allows us to participate in two-thirds of price declines but only one-third of price increases. As of December 31, 2006, we have not entered into any hedging activities. When we do enter into hedging activities, we will determine whether they meet the definition of normal sales and purchases and if not, we will determine whether we can use hedge accounting.


We have no exposure to equity risk, as we do not hold any equity instruments.  Our exposure to interest rate risk is limited to investments held for environmental costs, the water sale long term receivable and short-term borrowings on the line of credit.  The investments held for environmental costs are short-term fixed income debt securities whose carrying amounts are not materially different than fair value.  The short-term borrowings were $3.5 million at the end of December 2006.  Therefore, we do not believe we have material market risk exposure related to these instruments.  The indentures governing our two first mortgage bond series outstanding contain "make-whole" provisions, which are pre-payment penalties that charge for lost interest, which render refinancing impracticable.


Our non-interest bearing long-term receivable from the sale of the water operations was discounted at 4.34%. A hypothetical 0.5% (50 basis points) increase in the interest rate used would change the current fair value from $6 million to $5.9 million.


In 2006, a hypothetical 0.5% (50 basis points) decrease in the long-term interest rate on $52.5 million debt excluding unamortized debt discount would change the fair value from $63 million to $66.9 million.


Changes in short-term interest rates could have an effect on income depending on the balance borrowed on the variable rate line of credit.  We had short-term debt of $3.5 million on December 31, 2006 and $9.6 million on December 31, 2005.  A hypothetical 1% increase in interest rates would have resulted in a decrease in annual earnings for 2006 by $35,000 and for 2005 by $96,000, based on year-end borrowings.


Item 8.     Financial Statements and Supplementary Data


CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31

Revenues

 

2006

 

2005

 

2004

Natural gas

$ 

             71,139 

$ 

69,094 

$ 

55,962 

Electric

 

48,527 

 

47,450 

 

42,910 

Propane gas

 

14,727 

 

13,479 

 

11,167 

Total revenues

 

134,393 

 

130,023 

 

110,039 

Cost of Fuel and Other Pass Through Costs

 

85,971 

 

82,804 

 

69,350 

Gross Profit

 

48,422 

 

47,219 

 

40,689 

Operating Expenses

 

 

 

 

 

 

Operation

 

24,034 

 

22,881 

 

20,068 

Maintenance

 

3,484 

 

3,566 

 

2,982 

Depreciation and amortization

 

7,742 

 

7,266 

 

5,900 

Taxes other than income taxes

 

2,985 

 

2,869 

 

2,753 

Total operating expenses

 

38,245 

 

36,582 

 

31,703 

Operating Income

 

10,177 

 

10,637 

 

8,986 

Other Income and (Deductions)

 

 

 

 

 

 

Merchandise and service revenue

 

4,322 

 

4,590 

 

3,366 

Merchandise and service expenses

 

(4,071)

 

(4,664)

 

(3,326)

Other income

 

620 

 

569 

 

625 

Other deductions

 

(33)

 

(29)

 

20 

Interest expense on long-term debt

 

(3,949)

 

(3,949)

 

(3,949)

Interest expense on short-term borrowings

 

(108)

 

(79)

 

(42)

Customer deposits and other interest expense

 

(551)

 

(540)

 

(471)

Total other deductions – net

 

(3,770)

 

(4,102)

 

(3,777)

Earnings Before Income Taxes

 

             6,407 

 

6,535 

 

5,209 

Income Taxes

 

(2,238)

 

(2,287)

 

(1,615)

Net Income

 

4,169 

 

4,248 

 

3,594 

Preferred Stock Dividends

 

29 

 

29 

 

29 

Earnings for Common Stock

$

4,140 

$ 

4,219 

$ 

3,565 

Earnings Per Common Share (basic and diluted)

$

.69 

$ 

.71 

$ 

.60 

Dividends Declared Per Common Share

$

.43 

$ 

.41 

$ 

.40 

Average Shares Outstanding

 

5,993,589 

 

5,952,684 

 

5,908,220 



See Notes to Consolidated Financial Statements



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31

 

 

2006

 

2005

 

2004

Net income

$ 

4,169 

$ 

4,248 

$ 

3,594 

Other comprehensive income/(loss), net:

 

 

 

 

 

 

    Retirement plans adjustment

 

(166)

 

- 

 

- 

       Deferred income taxes benefit

 

63 

 

- 

 

- 

Comprehensive income

$

4,066 

$ 

4,248 

$ 

3,594 


See Notes to Consolidated Financial Statements



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

 

December 31,

ASSETS

 

2006

 

2005

Utility Plant

 

 

 

 

Natural gas

$

95,393 

$ 

89,835 

Electric

 

72,776 

 

70,084 

Propane gas

 

17,153 

 

15,500 

Common

 

3,646 

 

3,859 

Total

 

188,968 

 

179,278 

Less accumulated depreciation

 

59,757 

 

56,217 

Net utility plant

 

129,211 

 

123,061 

 

 

 

 

 

Current Assets

 

 

 

 

Cash

 

84 

 

695 

Accounts receivable

 

12,199 

 

15,780 

Notes receivable

 

298 

 

299 

Allowance for uncollectible accounts

 

(429)

 

(272)

Unbilled receivables

 

1,957 

 

1,918 

Inventories (at average or unit cost)

 

4,120 

 

3,781 

Prepaid expenses

 

962 

 

951 

Income tax prepayments

 

98 

 

1,159 

Under-recovery of fuel costs

 

862 

 

3,375 

Total current assets

 

20,151 

 

27,686 

 

 

 

 

 

Other Assets

 

 

 

 

Investments held for environmental costs

 

3,364 

 

3,258 

Other regulatory assets – storm reserve

 

270 

 

452 

Other regulatory assets – environmental

 

8,284 

 

8,868 

Other regulatory assets – retirement plans

 

587 

 

- 

Long-term receivables and other investments

 

5,740 

 

5,794 

Deferred charges

 

6,496 

 

6,751 

Goodwill

 

2,405 

 

2,405 

Intangible assets (net)

 

4,405 

 

4,391 

Total other assets

 

31,551 

 

31,919 

Total

$

180,913 

$ 

182,666 


  See Notes to Consolidated Financial Statements



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)    

 

 

December 31,

CAPITALIZATION AND LIABILITIES

 

2006

 

2005

Capitalization

 

 

 

 

Common shareholders' equity

$

47,572 

$ 

45,503 

Preferred stock

 

600 

 

600 

Long-term debt

 

50,702 

 

50,620 

Total capitalization

 

98,874 

 

96,723 

 

 

 

 

 

Current Liabilities

 

 

 

 

Line of credit

 

3,466 

 

9,558 

Accounts payable

 

10,279 

 

13,166 

Insurance accrued

 

181 

 

296 

Interest accrued

 

789 

 

1,014 

Other accruals and payables

 

2,185 

 

 1,984 

Taxes accrued

 

1,277 

 

1,512 

Deferred income tax

 

579 

 

1,066 

Over-earnings liability

 

722 

 

700 

Over-recovery of fuel costs

 

3,656 

 

- 

Over-recovery of conservation

 

355 

 

24 

Customer deposits

 

9,608 

 

8,851 

Total current liabilities

 

33,097 

 

38,171 

 

 

 

 

 

Other Liabilities

 

 

 

 

Deferred income taxes

 

16,104 

 

17,568 

Unamortized investment tax credits

 

335 

 

411 

Environmental liability

 

13,753 

 

14,001 

Regulatory liability – cost of removal

 

8,800 

 

8,256 

Regulatory tax liabilities

 

876 

 

991 

Long-term medical and pension reserve

 

4,731 

 

2,663 

Customer advances for construction

 

2,707 

 

2,346 

Regulatory liability – storm reserve

 

1,636 

 

1,536 

Total other liabilities

 

48,942 

 

47,772 

Total

$

180,913 

$ 

182,666 


See Notes to Consolidated Financial Statements

 

 

 

 




 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in thousands)

 

 

December 31,

 

 

2006

 

2005

Common Shareholders' Equity

 

 

 

 

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,166,648 shares in 2006; issued 6,152,676 shares in 2005

$

9,250 

$ 

9,229 

Paid-in capital

 

6,054 

 

5,998 

Retained earnings

 

35,213 

 

33,625 

Accumulated other comprehensive income/(loss), retirement plan adjustment, net of income tax benefit

 

(103)

 

- 

Treasury stock - at cost (160,349 shares in 2006, 188,994 shares in 2005)

 

(2,842)

 

(3,349)

Total common shareholders' equity

 

47,572 

 

45,503 

Preferred Stock

 

 

 

 

4 ¾% Series A, $100 par value, redemption price $106, authorized and outstanding 6,000 shares

 

600 

 

600 

 

 

 

 

 

4 ¾% Series B Cumulative Preferred, $100 par value, redemption price $101, authorized 5,000 and none issued

 

- 

 

- 

 

 

 

 

 

$1.12 Convertible Preference, $20 par value, redemption price $22, authorized 32,500 and none issued

 

- 

 

- 

Total preferred stock

 

600 

 

600 

Long-Term Debt

 

 

 

 

First mortgage bonds series

 

 

 

 

9.57 % due 2018

 

10,000 

 

10,000 

10.03 % due 2018

 

5,500 

 

5,500 

9.08 % due 2022

 

8,000 

 

8,000 

4.90 % due 2031

 

14,000 

 

14,000 

6.85 % due 2031

 

15,000 

 

15,000 

                Unamortized debt discount

 

(1,798)

 

(1,880)

Total long-term debt

 

50,702 

 

50,620 

Total Capitalization

$

98,874 

$ 

96,723 

See Notes to Consolidated Financial Statements

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Common Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

 Shares Issued

 

 Aggregate Par Value

 

 Paid-in Capital

 

 Retained Earnings

 

Accumulated Other Comprehensive (Loss)

 

 Treasury Shares Cost

 

 Treasury Shares

 

 Common Shareholders’ Equity

Balances as of December 31, 2003

6,097,478

 

 $9,146 

 

$5,632

 

$30,638

 

 $     - 

 

$(3,953)

 

223,062

 

 $41,463 

Net income

 - 

 

 - 

 

 - 

 

 3,594 

 

 - 

 

 - 

 

 - 

 

 3,594 

Dividends

 - 

 

 - 

 

 - 

 

 (2,383)

 

 - 

 

 - 

 

 - 

 

 (2,383)

Stock plans

 32,619 

 

 49 

 

 174 

 

 - 

 

 - 

 

 316 

 

(17,821)

 

 539 

Balances as of December 31, 2004

6,130,097

 

 9,195 

 

 5,806 

 

 31,849 

 

 - 

 

(3,637)

 

205,241

 

 43,213 

Net income

 - 

 

 - 

 

 - 

 

 4,248 

 

 - 

 

 - 

 

 - 

 

 4,248 

Dividends

 - 

 

 - 

 

 - 

 

 (2,472)

 

 - 

 

 - 

 

 - 

 

         (2,472)

Stock plans

 22,579 

 

 34 

 

 192 

 

 - 

 

 - 

 

 288 

 

       (16,247)

 

 514 

Balances as of December 31, 2005

6,152,676

 

 9,229 

 

 5,998 

 

 33,625 

 

 

 

       (3,349)

 

188,994

 

 45,503 

Net income

 - 

 

 - 

 

 - 

 

 4,169 

 

 - 

 

 - 

 

 - 

 

 4,169 

Other comprehensive loss, retirement plans adjustment, net of tax

 - 

 

 - 

 

 - 

 

 - 

 

          (103)

 

 - 

 

 - 

 

            (103)

Dividends

 - 

 

 - 

 

 - 

 

 (2,581)

 

 - 

 

 - 

 

 - 

 

 (2,581)

Stock plans

 13,972 

 

 21 

 

 56 

 

 - 

 

 - 

 

 507 

 

       (28,645)

 

 584 

Balances as of December 31, 2006

6,166,648

 

 $9,250 

 

$6,054

 

$35,213

 

 $      (103)

 

$(2,842)

 

160,349

 

 $47,572 


See Notes to Consolidated Financial Statements



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

 

 

Years Ended December 31,

 

 

2006

 

2005

 

2004

Cash Flows from Operating Activities:

 

 

 

 

 

 

Net income

$

4,169 

$ 

4,248 

$ 

3,594 

Adjustments to reconcile net income to net cash from operating activities:

 

 

 

 

 

 

Depreciation and amortization

 

7,742 

 

7,266 

 

5,900 

Deferred income taxes

 

(2,003)

 

(153)

 

2,470 

Bad debt expense

 

623 

 

359 

 

409 

Investment tax credits

 

(75)

 

(81)

 

(83)

Other

 

805 

 

751 

 

121 

Interest income from sale of non-utility property

 

(252)

 

(192)

 

(271)

Compensation expense from the issuance of stock

 

88 

 

58 

 

91 

Effects of changes in:

 

 

 

 

 

 

Receivables

 

3,115 

 

(4,513)

 

(1,688)

Unbilled receivables

 

(39)

 

367 

 

(612)

Inventories and prepayments

 

711 

 

(495)

 

2,746 

Accounts payable and accruals

 

(976)

 

5,560 

 

1,131 

Over (under) recovery of fuel and other pass through costs

 

6,500 

 

(3,171)

 

(1,991)

Area expansion program deferred costs

 

238 

 

109 

 

(372)

Environmental liability

 

584 

 

429 

 

(586)

Other

 

(1,140)

 

(329)

 

814 

     Net cash provided by operating activities

 

20,090 

 

10,213 

 

11,673 

Cash Flows from Investing Activities:

 

 

 

 

 

 

Construction expenditures

 

(13,116)

 

(12,441)

 

(13,731)

Customer advances received for construction

 

361 

 

454 

 

144 

Purchase of long-term investments

 

(106)

 

(75)

 

(34)

Proceeds received on notes receivable

 

321 

 

304 

 

57 

Issuance of notes receivable

 

- 

 

- 

 

(95)

      Other

 

(15)

 

- 

 

- 

     Net cash used in investing activities

 

(12,555)

 

(11,758)

 

(13,659)

Cash Flows from Financing Activities:

 

 

 

 

 

 

Net change in short-term borrowings

 

(6,092)

 

3,733 

 

3,547 

Proceeds from common stock plans

 

497 

 

456 

 

447 

Dividends paid

 

(2,551)

 

(2,448)

 

(2,368)

     Net cash provided by (used in) financing activities

 

(8,146)

 

1,741 

 

1,626 

Net Increase (Decrease) in Cash

 

(611)

 

196 

 

(360)

Cash at Beginning of Year

 

695 

 

499 

 

859 

Cash at End of Year

$

84 

$ 

695 

$ 

499 

Supplemental Cash Flow Information

 

 

 

 

 

 

Cash was paid during the years as follows:

 

 

 

 

 

 

     Interest

$

4,777 

$ 

4,469 

$ 

4,357 

     Income taxes

$

3,298 

$ 

2,698 

$ 

1,215 



See Notes to Consolidated Financial Statements


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.

Summary of Significant Accounting and Reporting Policies


A. General

The Company is an operating public utility engaged principally in the purchase, transmission, distribution and sale of electricity and in the purchase, transmission, distribution, sale and transportation of natural gas.  The Company is subject to the jurisdiction of the FPSC with respect to its natural gas and electric operations.  The suppliers of electric power to the Northwest Florida division and of natural gas to the natural gas divisions are subject to the jurisdiction of the FERC.  The Northeast Florida division is supplied most of its electric power by a municipality which is exempt from FERC and FPSC regulation.  The Company also distributes propane gas through a non-regulated subsidiary.


B. Basis of Presentation

The consolidated financial statements include the accounts of Florida Public Utilities Company (FPU) and its wholly owned subsidiary, Flo-Gas Corporation. All significant intercompany balances and transactions have been eliminated. The Company’s accounting policies and practices conform to accounting principles generally accepted in the United States of America (GAAP) as applied to regulated public utilities and are in accordance with the accounting requirements and rate-making practices of the FPSC and in accordance to the rule requirements of the Securities and Exchange Commission (SEC).


C. Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Some of these estimates include the accruals for pensions, allowances, environmental liabilities, liability reserves, unbilled revenue, regulatory deferred tax liabilities and over-earnings liability.  Actual results may differ from these estimates and assumptions.


D. Reclassifications

Certain amounts in the prior years' financial statements have been reclassified to conform to the 2006 presentation.


E. Regulation

The financial statements are prepared in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 – "Accounting for the Effects of Certain Types of Regulation".  SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the relationship of costs and revenues introduced by rate regulation.  A regulated utility may defer recognition of a cost (a regulatory asset) or show recognition of an obligation (a regulatory liability) if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in revenues.  The Company has recognized certain regulatory assets and liabilities in the consolidated balance sheets.  The Company believes that the FPSC will continue to allow recovery of such items through rates.  As these regulatory assets and liabilities are recovered through rates or paid through a reduction of rates, the assets and liabilities are amortized to revenue and expense. In the event that a portion of the Company’s operations are no longer subject to the provisions of SFAS No. 71, the Company would be required to write-off related regulatory assets and liabilities that are not specifically recoverable through regulated rates.  In addition, the Company would be required to determine if an impairment related to other assets exists, including plant, and write-down the assets, if impaired, to their fair value.



 

 

 

 

 

 

 

 

 

Summary of Regulatory Assets and Liabilities

(Dollars in thousands)

 

2006 

2005 

Assets

 

 

Deferred development costs  (1)

$  3,952 

$  4,190 

Unamortized fuel related regulatory costs (6)

48 

24 

Environmental assets (2)

8,284 

8,868 

Storm Reserve assets (3)

270 

452 

Deferred retirement plan costs (5)

587 

- 

Unamortized Rate Case expense

368 

541 

Under-recovery of fuel costs

862 

3,375 

Unamortized piping and conversion costs   (1)

1,521

1,587

Unamortized loss on reacquired debt   (1)

209 

227 

Total Regulatory Assets

$16,101 

$19,264 

  

 

 

Liabilities

 

 

Tax liabilities

$     876 

$     991 

Cost of removal

8,800 

8,256 

Storm reserve liabilities

1,636 

1,536 

Over-recovery of fuel costs

3,656 

- 

Over-recovery of conservation

355 

24 

Over-earnings liability (4)

722 

700 

Total Regulatory Liabilities

       $16,045 

$11,507 


(1)

Deferred development costs, unamortized piping and conversion costs, and unamortized loss on reacquired debt are included in deferred charges in the consolidated balance sheets.

(2)

The Company has included the amount due from customers as a regulatory asset for environmental costs. The FPSC authorized recovery of these environmental costs from customers over 20 years.

(3)

The FPSC has authorized the Company to recover storm damages incurred in 2004 in their natural gas operations. Recovery of these costs from customers over 30 months began November 2005.

(4)

The Company originally estimated the 2005 over-earnings for regulated natural gas operations at $700,000. In 2006 the estimate was reduced to $650,000. The Company has estimated 2006 over-earnings for regulated natural gas operations of $72,000. The Company has recorded these liabilities which reduced revenues. The FPSC determines the disposition of over-earnings with alternatives that include refunding to customers, funding storm damage or environmental reserves, or reducing any depreciation reserve deficiency.

(5)

The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 at December 31, 2006 resulted in a regulatory asset for the portion of the loss of $587,000 to be recovered in future rate proceedings.

(6)

The Company has deferred certain regulatory fuel related costs and as of January 2006 has been amortizing these over five years according to a FPSC order in the November 2005 fuel hearings.


The base revenue rates for regulated segments are determined by the FPSC and remain constant until a request for an increase is filed and approved by the FPSC or the FPSC orders the Company to reduce their rates.  For the Company to recover increased costs from the effects of inflation and construction expenditures for regulated segments, a request for an increase in base revenues would be required. Separate filings would be required for the electric and natural gas segments.  The Company is currently seeking rate relief for electric storm preparedness initiatives required in 2007.


F. Derivatives

None of the Company’s gas or electric contracts are accounted for using the fair value method of accounting. All material contracts that meet the definition of derivative instruments are considered "normal purchases and sales" under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities”.


G. Revenue Recognition

The Company’s revenues consist of base revenues, fuel adjustment charges, conservation charges and the pass-through of certain governmental imposed taxes based on revenues.


The FPSC approves base revenue rates that are intended to permit a specified rate of return on investment and limits the maximum amount of earnings of regulated operations.   Fuel adjustment charges, conservation charges and the pass-through of certain governmental imposed taxes based on revenues are approved by the FPSC to allow recovery of fuel, conservation and revenue based taxes from the Company’s customers.  Any over or under-recovery of these expense items are deferred and subsequently refunded or collected in the following period.


Annually, any earnings in excess of this maximum amount permitted in the base rates are accrued for as an over-earnings liability and revenues are reduced an equivalent amount. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations. The FPSC determines the disposition of any over-earnings with alternatives that include refunding to customers, funding storm damage or environmental reserves, or reducing any depreciation reserve deficiency.


The Company bills utility customers on a monthly cycle basis; however, the billing cycle periods for most customers do not coincide with the accounting periods used for financial reporting.  The Company accrues estimated revenue for gas and electric customers on usage not yet billed for the accounting period.  Determination of unbilled revenue relies on the use of estimates, fuel purchases and historical data.


H. Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts based on historical information and trended current economic conditions.  The following is a summary of the activity in Allowance for Doubtful Accounts for the years ending December 31:


 

 

 

 

 

 

 

 

 

 

Allowance for Doubtful Accounts

(Dollars in thousands)

 

Balance at Beginning of Year

Write-offs

Provisions to Bad Debt Expense

Balance at End of Year

2004

$ 180

320

409

$ 269

2005

$ 269

356

359

$ 272

2006

$ 272

466

623

$ 429



I. Utility Plant and Depreciation

Utility plant is stated at original cost.  The propane gas utility plant that has been acquired in acquisitions was stated at fair market value when acquired.  Additions to utility plant include contracted services, direct labor, transportation and materials for additions.  Units of property are removed from utility plant when retired.  Maintenance and repairs of property and replacement and renewal of items determined not to be units of property are charged to operating expenses.  Substantially all of the utility plant and the shares of Flo-Gas Corporation collateralize the Company's first mortgage bonds.


 

 

 

 

 

 

 

 

 

 

 

 

Utility Plant

 

(Dollars in thousands)

 

Plant Classification

Annual Composite Depreciation Rate

2006 

2005 

Land

 

$      1,130 

$      1,124 

Buildings

2.0% to 4.9%

6,991 

6,862 

Distribution

2.0% to 8.6%

158,010 

147,580 

Transmission

2.2% to 3.8%

6,878 

6,799 

Equipment

2.0% to 20.0%

12,700 

11,534 

Furniture and Fixtures

4.8% to 20.0%

392 

369 

Work-in-Progress

 

2,867 

5,010 

 

 

$ 188,968 

$ 179,278 


Depreciation for the Company’s regulated segments is computed using the composite straight-line method at rates prescribed by the FPSC for financial accounting purposes.  Propane gas depreciation is computed using a composite straight-line method at an average rate based on estimated average life of approximately 20-30 years.  Such rates are based on estimated service lives of the various classes of property.  Depreciation provisions on average depreciable property approximate 3.9% in 2006, 3.9% in 2005 and 3.6% in 2004.


J. Impact of Recent Accounting Standards


Financial Accounting Standard Board Interpretation No. 48

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48).  The interpretation clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes.  The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.  This interpretation is effective for calendar years beginning January 1, 2007.

 

We have performed an analysis of tax positions taken and expected to be taken on the tax returns and assessed the technical merits of each tax position by relying on legislation, statutes, common legislative intent, regulations, rulings and case law and determined that the Company has no material uncertain tax positions.   Additionally, the IRS concluded an audit of the 2002 and 2003 tax years in September of 2005.

 

In February of 2007, the IRS informed us that it selected our 2003 and 2004 tax years for examination.  As our tax positions have remained consistent with those from the previously audited tax years, we are not expecting any material adverse findings as the result of the impending IRS audit.

 

Based on the aforementioned, we believe that the adoption of FASB Interpretation No. 48 will not have a material impact on our financial condition or results of operations.


Financial Accounting Standard No. 157

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements”.  This Statement clarifies fair value as the market value received to sell an asset or paid to transfer a liability, that is, the exit value, and applies to any assets or liabilities that require recurring determination of fair value.  The measurement includes any applicable risk factors and does not include any adjustment for volume.  This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within. The Company expects to adopt SFAS No. 157 effective January 1, 2008. The Company does not believe adoption of this Statement will have a material impact on our financial condition or results of operation.


Financial Accounting Standard No. 158

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”. Statement 158 requires the Company to show the funded status of its pension and retiree health care plans as a prepaid asset or accrued liability, and to show the net deferred and unrecognized gains and losses related to the retirement plans, net of tax, as part of accumulated other comprehensive income in shareholders’ equity.  Previously, the net deferred and unrecognized gains and losses were netted in the prepaid asset or accrued liability recorded for the retirement plans. The Company adopted the recognition provisions of Statement 158, as required, at December 31, 2006.


The Company uses December 31 as the measurement date to measure the assets and obligations of its retirement plans.  Statement 158 will also require the Company to use December 31 as the measurement date no later than fiscal years ending after December 15, 2008.  The Company currently uses this date as the measurement date, and has used it for all periods presented.


The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 at December 31, 2006 resulted in an additional liability for retirement plans. The tax on the non-regulated portion of this liability has been recorded as a deferred income tax asset. As an offset, the regulatory portion of this liability has been deferred as a regulatory asset-retirement plans to be recovered in future rate proceedings and the remaining expense from recording the liability has been included in other comprehensive income.  The fair value of retirement plan assets and obligations are subject to change based on market fluctuations. The table below summarizes the effects to our financial statements.


 

 

 

 

 

 

 

 

FASB 158 Implementation Summary

(Dollars in thousands)

 

December 31, 2006

 

Before Application of SFAS 158

Adjustment

After Application of SFAS 158

Assets:

 

 

 

Other regulatory assets- retirement plans

    $          - 

 $587 

$587


Liabilities and Equity:

 

 

 

Accumulated other comprehensive income/(loss)

       - 

 (103)

(103)

Other accruals and payables

2,034 

151 

2,185 

Long term medical and pension reserve

4,129 

602 

4,731 

Deferred income taxes

16,167 

 (63)

16,104 


Staff Accounting Bulletin No. 108

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108 “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”.  SAB 108 requires that public companies utilize a “dual-approach” to assessing the quantitative effects of financial misstatements.  This dual approach includes an assessment from both an income statement and a balance sheet focus.  The guidance in SAB 108 must be applied to annual financial statements for fiscal years ending after November 15, 2006.  The Company has adopted SAB No.108 and there has not been any impact on our consolidated financial position or results of operations as the result of this adoption.


2.  Goodwill and Intangible Assets

In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets", the Company does not amortize goodwill or intangibles with indefinite lives.  The Company periodically tests the applicable reporting segments, natural gas and propane gas, for impairment. In the event a segment becomes impaired, the Company would write down the associated goodwill and intangible assets to fair value. The impairment tests performed in 2005 and 2006 showed no impairment for either reporting segment.


Goodwill associated with the Company’s acquisitions is identified as a separate line item on the consolidated balance sheet and consists of $1.9 million in the propane gas segment and $500,000 in the natural gas segment.


Intangible assets associated with the Company’s acquisitions and software have been identified as a separate line item on the balance sheet.  Summaries of those intangible assets at December 31 are as follows:


 

 

 

 

 

 

 

 

 

 

 

 

Intangible Assets

(Dollars in thousands)

 

 

2006 

2005 

Customer distribution rights

(Indefinite life)

$ 1,900 

$ 1,900 

Customer relationships

(Indefinite life)

900 

900 

Software

(Five to nine year life)

3,122 

2,971 

Non-compete agreement

(Five year life)

- 

35 

Accumulated amortization

(1,517)

(1,415)

Total intangible assets, net of amortization

$4,405 

$ 4,391 


The 2006 amortization expense of computer software is approximately $300,000. The Company expects the amortization expense of computer software to be approximately $300,000 annually over the next five years, with the current level of software investment. The non-compete agreements expired in 2006.


3. Over-earnings-Natural Gas

The FPSC approves rates that are intended to permit a specified rate of return on investment and limits the maximum amount of earnings of regulated operations. The Company has agreed with the FPSC staff to limit the earned return on equity for regulated natural gas and electric operations.


The Company estimated 2005 over-earnings for regulated natural gas operations of $700,000. The 2005 over-earnings estimate was revised in 2006 to be $650,000. The Company estimated 2006 over-earnings for regulated natural gas operations of $72,000. These liabilities have been included in the over-earnings liability on the Company’s balance sheet. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations.


The Company feels the estimates of the 2005 and 2006 over-earnings liabilities are accurate, but the amounts could change upon the FPSC finalization and review of earnings expected in 2007 and 2008. The FPSC determines the disposition of over-earnings with alternatives that include refunding to customers, increasing storm damage or environmental reserves or reducing any depreciation reserve deficiency.


4. Storm Reserves

As of December 31, 2006, the electric segment storm reserve was approximately $1.6 million. Since the last order on the 1999 disposition of electric over-earnings, the FPSC has allowed the Company the flexibility of automatically applying the electric over-earnings to the storm damage reserves each year since 1999 and allowing additional storm damage accruals up to a cap of $2.9 million. In 2006, 2005 and 2004 there were no electric over-earnings and accordingly no additional over-earnings amounts were added to the storm damage reserves.


In October 2005, the FPSC approved recovery of 2004 natural gas segment storm costs plus interest and revenue taxes over a 30-month period beginning November 2005.  The Company deferred storm costs as a regulatory asset due from customers on the balance sheet. As of December 31, 2006, the unrecovered amount of natural gas regulatory asset relating to storm costs was $270,000.


The Company has requested that the FPSC allow 2005 over-earnings in natural gas to be used to recover the regulatory asset -storm and discontinue this storm surcharge. As part of this same request, the Company has also asked the FPSC to allow any excess over-earnings amount to provide additional funds for the “regulatory liability- storm reserve” for natural gas. We expect the FPSC to rule on this request during 2007.


In 2005, the FPSC approved applying 2002 natural gas over-earnings of $118,000 to the storm reserve to cover future storm costs.


5. Income Taxes

Deferred income taxes are provided on all significant temporary differences between the financial statements and tax basis of assets and liabilities at currently enacted tax rates.  Investment tax credits have been deferred and are amortized based upon the average useful life of the related property in accordance with the rate treatment.


A. Income Taxes related to Deferred Gain on Water Sale

On March 27, 2003, the Company sold substantially all of its assets of the water division to the City of Fernandina Beach.  The sale was made pursuant to a “threat of condemnation” during the fourth quarter of 2002.  For tax purposes the Company elected to defer the gain on the sale of the assets pursuant to Code Section 1033 of the Internal Revenue Code of 1986 (IRC).  Section 1033 allows non-recognition of gain if property is disposed as a result of threat of condemnation and property that is similar or related in service or use is purchased to replace the disposed property.  To qualify, the replacement property must be purchased within the replacement period, which begins on the earlier of date of disposition (March 27, 2003) or date of threat of condemnation (December 31, 2002) and ending two years after the close of the year of sale (December 31, 2005).  For real property, the replacement period is extended to three years (December 31, 2006).


The Company purchased property that is similar or related in service or use within the replacement periods with the exception of the intangible assets.  During the IRS audit in 2005, the IRS disallowed a portion, approximately $900,000 of the deferral relating to the intangible assets, since replacement was no longer expected.


A $2.9 million estimated tax payment was made in 2003 related to the gain on the sale of the water division.  It was subsequently determined that the income tax would be deferred.  The Company applied for a refund and received $3.9 million in July 2004, which included other estimated tax overpayments.



B. Provision for Income Taxes

The provision (benefit) for income taxes consists of the following:


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands)

 

Years ended December 31,

 

 

2006 

 

2005 

 

2004 

Current payable

 

 

 

 

 

 

  Federal

$

3,652 

$ 

2,150 

$ 

(566)

  State

 

664 

 

370 

 

(96)

    Current – net

 

4,316 

 

2,520 

 

(662)

Deferred

 

 

 

 

 

 

  Federal

 

(1,723)

 

(143)

 

2,003 

  State

 

(280)

 

(9)

 

358 

     Deferred – net

 

(2,003)

 

(152)

 

2,361 

 

 

 

 

 

 

 

Investment tax credit

 

(75)

 

(81)

 

(84)

 

 

 

 

 

 

 

Total income taxes

$

2,238 

$ 

2,287 

$ 

1,615 



C. Effective Tax Rate Reconciliation

The difference between the effective income tax rate and the statutory federal income tax rate applied to pretax income is of continuing operations accounted for as follows:


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 (Dollars in thousands)

 

Years ended December 31,

 

 

2006 

 

2005 

 

2004 

Federal income tax at statutory rate (34%)

$ 

2,178 

$ 

2,222 

$ 

1,771 

State income tax, net of federal benefit (5.5%)

 

233 

 

237 

 

189 

Investment tax credit

 

(75)

 

(81)

 

(84)

Tax exempt interest

 

(85)

 

(71)

 

(94)

Other

 

(13)

 

(20)

 

(167)

Total provision for income taxes

$ 

2,238 

$ 

2,287 

$ 

1,615 


D. Deferred Income Taxes


Temporary timing differences which produce deferred income taxes in the accompanying consolidated balance sheets are as follows:


 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands)

Years ended December 31,

Deferred tax assets:

2006 

 

2005 

   Environmental

$    2,063 

 

 $        1,932 

   Self insurance

774 

 

731 

   Storm reserve liability

509 

 

408 

   Vacation pay

357 

 

320 

   Other deferred credits

15 

 

61 

   Allowance for uncollectible accounts receivable

162 

 

103 

   General liability

68 

 

111 

   Rate refund

271 

 

263 

   Pension

789 

 

286 

   Under/over-recovery of conservation costs

134 

 

 9 

   Other

37 

 

37 

Total deferred tax assets

    5,179 

 

       4,261 

Deferred tax liabilities:

 

 

 

   Utility plant related

   20,274 

 

      20,319 

   Deductible intangibles

696 

 

577 

   Under-recovery of fuel costs

643 

 

1,704 

   Rate case expense

138 

 

204 

   Loss on reacquired debt

79 

 

85 

   Other

32 

 

6 

Total deferred tax liabilities

   21,862 

 

    22,895 

Net deferred income taxes liabilities

$   16,683 

 

$   18,634 


Deferred tax liabilities included in the consolidated balance sheets are as follows:


 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands)

2006 

 

2005 

 

 

 

 

Deferred income tax – current

 $        579 

 

$         1,066 

Deferred income tax – long term

16,104 

 

17,568 

Net deferred income tax liabilities

$   16,683 

 

$       18,634 


E. IRS Audit

The IRS has informed us that it has selected our 2003 and 2004 tax returns for examination. Management does not expect any material adjustments from the audit but the effects, if any, that result from the final resolution of this IRS audit will be recorded when they become known and estimable.  The Company expects the audit will be completed before the end of 2007.


The IRS completed an audit in 2005 of the Company’s 2002 and 2003 federal income tax returns. The audit resulted in a current income tax payable amount of $361,000 due to adjustments to depreciation, reserve accounts and recognition of a portion of the water sale gain that was previously deferred. This amount was partially offset by $285,000 in deferred tax liabilities previously established.


6.   Capitalization


A. Stock Dividend

On July 25, 2005 a three-for-two stock split in the form of a stock dividend was issued to the shareholders of record on July 15, 2005.   All common share information has been restated to reflect the stock split for all periods presented.


B. Common Shares Reserved

The Company has 3,833,352 authorized but unissued shares and 160,349 treasury shares as of December 31, 2006. The Company has reserved the following common shares for issuance as of December 31, 2006:


 

 

 

 

 

 

Dividend Reinvestment Plan

54,071 

Employee Stock Purchase Plan

52,035 

Board Compensation Plan

20,714 

 

 


C. Preferred Stock

The Company has 6,000 shares of 4 ¾% Series A preferred stock $100 par value authorized for issuance of which 6,000 were issued and outstanding at December 31, 2006. The preferred stock is included in stockholders’ equity on the balance sheet.


The Company also has 5,000, 4 ¾% Series B preferred stock $100 par value authorized for issuance none of which has been issued.


The Company also has 32,500, $1.12 Convertible Preference stock, $20 par value and $22 redemption price, authorized for issuance none of which has been issued.


D. Dividend Restriction

The Company’s Fifteenth Supplemental Indenture of Mortgage and Deed of Trust restricts the amount that is available for cash dividends.  At December 31, 2006, approximately $9 million of retained earnings were free of such restriction and therefore available for the payment of dividends.  The line of credit agreement contains covenants that, if violated, could restrict or prevent the payment of dividends. At December 31, 2006 the Company is not in violation of these covenants.


E. Treasury Shares

In prior years, common shares resulting from stock dividends have been allocated to common shares held as treasury shares.  Treasury shares are not eligible to receive such allocations.  Some of these treasury shares were subsequently reissued, resulting in an overstatement of additional paid-in capital.  Accordingly, the Company has restated all periods presented to reflect the correct number of treasury shares and the value of treasury shares and additional paid-in capital at each year-end. As the adjustment is a reallocation of amounts between treasury stock and additional paid-in capital, there is no effect on net income, earnings per common share or total stockholders’ equity in any period presented.


F. Employee Stock Purchase Plan

The Company’s Employee Stock Purchase Plan offers common stock at a discount to qualified employees.


G. Dividend Reinvestment Plan

The Company’s Dividend Reinvestment Plan is offered to all Company shareholders and allows the shareholder to reinvest dividends received and purchase additional shares without a fee.


7.  Long-term Debt

The Company issued its Fourteenth Series of FPU’s First Mortgage Bond on September 27, 2001 in the aggregate principal amount of $15 million as security for the 6.85% Secured Insured Quarterly Notes, due October 1, 2031 (IQ Notes).  Interest on the pledged bond accrues at the annual rate of 6.85% payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2002.


The Company issued $14 million of Palm Beach County municipal bonds (Industrial Development Revenue Bonds) on November 14, 2001 to finance development in the area.  The interest rate on the thirty-year callable bonds is 4.90%.  The bond proceeds were restricted and held in trust until construction expenditures were actually incurred by the Company.  In 2002 the remaining $8 million was drawn from the restricted funds held by the trustee.


In 1992, the Company issued its First Mortgage Bond 9.08% Series in the amount of $8 million. The thirty-year bond is due in June 2022.


The Company issued two of its Twelfth Series First Mortgage bond series on May 1, 1988; the 9.57% Series due 2018 in the amount of $10 million and 10.03% Series due 2018 in the amount of $5.5 million.  These two issuances require sinking fund payments of $909,000 and $500,000 respectively, beginning in 2008.


Long-term debt on the balance sheet has been reduced for unamortized debt discount. The unamortized debt discount at December 31 included in long-term debt on the balance sheet is $1.8 million in 2006 and $1.9 million in 2005.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Annual Maturities of Long-Term Debt

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

Total

2007

2008

2009

2010

2011

Thereafter

 

 

 

 

 

 

 

 

 

Long-term Debt

$52,500

-

$1,409

$1,409

$1,409

$1,409

$ 46,864



8.  Notes Payable

In 2004, FPU entered into an amended and restated loan agreement that allows the Company to increase the line of credit upon 30 days notice by the Company to a maximum of $20 million.  In 2006 the agreement was renewed with an expiration date of July 1, 2008. We have not exercised our option to increase the line of credit limit which is currently at $12 million with an outstanding balance of $3.5 million and a remaining amount available of $8.5 million.   The Company reserves $1 million of the line of credit to cover expenses for any major storm repairs in its Northwest Florida division.  An additional $250,000 of the line of credit is reserved for a ‘letter of credit’ insuring our propane facilities.


The average interest rates for the line of credit were as follows as of December 31:


 

 

 

 

 

 

Year

Rate

2006

6.2%

2005

5.3%

2004

3.3%


9. Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for investments held in escrow for environmental costs, notes payable, taxes accrued and other accrued liabilities approximate fair value.  The fair value of long-term debt excluding the unamortized debt discount is estimated by discounting the future cash flows of each issuance at rates currently offered to the Company for similar debt instruments of comparable maturities.  The values at December 31 are shown below.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

2005


(Dollars in thousands)

Carrying

Amounts

Approximate Fair Value

Carrying

Amounts

Approximate Fair Value

Long-term debt

$ 52,500

$63,000

$52,500

$ 63,000


10. Contingencies


Environmental

The Company is subject to federal and state legislation with respect to soil, groundwater and employee health and safety matters and to environmental regulations issued by the Florida Department of Environmental Protection (FDEP), the United States Environmental Protection Agency (EPA) and other federal and state agencies.  Except as discussed below, the Company does not expect to incur material future expenditures for compliance with existing environmental laws and regulations.

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

Site

Range From

Range To

West Palm Beach

$      4,801

$   18,027

Sanford

710

710

Pensacola and Other

110

110

Total

$      5,621

$   18,847


The Company currently has $13.8 million reserved as an environmental liability. The FPSC approved up to $14 million for total recovery from insurance and rates based on the original 2005 projections as a basis for rate recovery.  The Company has recovered a total of $5.5 million from insurance and rate recovery, net of costs incurred to date.  The remaining balance of $8.3 million is recorded as a regulatory asset.  On October 18, 2004 the FPSC approved recovery of $9.1 million for environmental liabilities (the remaining amount to be recovered is $8.3 million and is included on the balance sheet as “Other regulatory assets – environmental”).  The amortization of this recovery and reduction to the regulatory asset began on January 1, 2005. The majority of environmental cash expenditures are expected to be incurred before 2010, but may continue for another 10 years.


West Palm Beach Site

The Company is currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by it in West Palm Beach, Florida upon which the Company previously operated a gasification plant. The Company entered into a Consent Order with the FDEP effective April 8, 1991, that requires the Company to delineate the extent of soil and groundwater impacts associated with the prior operation of the gasification plant and to remediate such soil and groundwater impacts, if necessary. The Company completed the delineation of soil and groundwater impacts at the site in October 2006. An engineering consultant was retained to perform a feasibility study to evaluate appropriate remedies for the site. The feasibility study was transmitted to FDEP on November 30, 2006.


The feasibility study evaluated a wide range of remedial alternatives based on criteria provided by applicable laws and regulations. The total costs for the remedies evaluated in the feasibility study ranged from a low of $2.8 million to a high of $54.6 million. Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, consulting/remediation costs to address the impacts now characterized at the West Palm Beach site are projected to range from $4.6 million to $17.9 million. This range of costs covers such remedies as in situ solidification for deeper soil impacts, excavation of superficial soil impacts, installation of a barrier wall with a permeable biotreatment zone (PBZ), monitored natural attenuation of dissolved impacts in groundwater (MNA) or some combination of these remedies. The feasibility study proposed a remedy of superficial soil excavation, and installation of a hanging barrier wall with PBZ and MNA, the cost of which is projected to range from $4.6 million to $9.9 million.


Prior to FDEP's approval of a final remedy for the site, the Company is unable to determine, to a reasonable degree of certainty, the complete extent or cost of remedial action that may be required. As of December 31, 2006, and subject to the limitations described above, remediation costs (including attorneys' fees and costs) for this site are projected to range from approximately $4.8 million to $18 million.


Sanford Site

The Company owns a parcel of property located in Sanford, Florida, upon which a gasification plant was operated prior to its acquisition of the property. Following discovery of soil and groundwater impacts on the property, the Company has participated with four former owners and operators of the gasification plant in the funding of numerous investigations of the extent of the impacts and the identification of an appropriate remedy. On or about March 25, 1998, the Company executed an Administrative Order on Consent (AOC) with the four former owners and operators (collectively, the Group) and the EPA that obligated the Group to implement a Remedial Investigation/Feasibility Study (RI/FS) and to pay EPA's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (WFS Participation Agreement). Work under the RI/FS AOC and RI/FS Participation Agreement is now complete and the Company has no further obligations under either document.


In late September 2006, EPA sent a Special Notice Letter to the Company, notifying the Company of EPA’s selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments), and giving the Company and the other Group members sixty (60) days within which to submit a "good faith offer" to EPA to provide for implementation of the selected remedies. The Special Notice Letter included an Amended Record of Decision (ROD) for OU1 (the ROD for OU1 was amended to account for a significant increase in the volume of off-site soil impacts and a change in the selected remedy), the original ROD for OU2, and a ROD for OU3. The total estimated remediation costs for the Sanford Gasification Plant Site are now projected to be $12.5 million. On November 30, 2006, the Company and the Group submitted to EPA a good faith offer to implement the approved remedies as set forth in the RODs for OU1 through OU3.


In January, the Company along with the other members of the Group signed a Third Participation Agreement, which provides for funding the remediation work specified in the RODs for OU1 through OU3 and supercedes and replaces the Second Participation Agreement. The Company’s share of remediation costs under the Third Participation Agreement is set at 5% of a maximum of $13 million, or $650,000.  At present, it is not anticipated that the total cost of remediation will exceed $13 million.  If it does, the Group members have agreed to negotiate in good faith to allocate the excess costs at such time that it reasonably appears that the total remediation costs will exceed $13 million.  In any such event, the Company does not expect our share of such additional costs to be greater than 5%; and its share of such additional costs may be less than 5%.


The Company’s future legal costs and expenses and its share future remediation expenses for this site are currently projected to be approximately $710,000.


Pensacola Site

The Company is the prior owner/operator of the former Pensacola gasification plant, located in Pensacola, Florida. Following notification on October 5, 1990 that FDEP had determined that the Company was one of several responsible parties for any environmental impacts associated with the former gasification plant site, the Company entered into cost sharing agreements with three other responsible parties providing for the funding of certain contamination assessment activities at the site.


Following field investigations performed on behalf of the responsible parties, on July 16, 1997, FDEP approved a final remedy for the site that provides for annual sampling of selected monitoring wells. Such annual sampling has been undertaken at the site since 1998. The Company’s share of these costs is less than $2,000 annually or a total of $27,000.


In March 1999, EPA requested site access in order to undertake an Expanded Site Inspection (ESI). The ESI was completed by EPA's contractor in 1999 and an ESI Report was transmitted to the Company in January 2000. The ESI Report recommends additional work at the site. The responsible parties met with FDEP on February 7, 2000 to discuss EPA's plans for the site. In February 2000, EPA indicated preliminarily that it will defer management of the site to FDEP; however, as of December 31, 2006, the Company has not received any written confirmation from EPA or FDEP regarding this matter. Prior to receipt of EPA's written determination regarding site management, the Company is unable to determine whether additional field work or site remediation will be required by EPA and, if so, the scope or costs of such work.


Key West Site

From 1927 to 1938, the Company owned and operated a gasification plant in Key West, Florida. The plant discontinued operations in the late 1940s; the property on which the plant was located is currently used for a propane gas distribution business. In March 1993, a Preliminary Contamination Assessment Report (PCAR) was prepared by a consultant jointly retained by the Company and the current site owner and was delivered to FDEP. The PCAR reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, FDEP notified the Company that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." FDEP then referred the matter to its Marathon office for consideration of whether additional work would be required by FDEP's district office under Florida law. As of December 31, 2006, the Company has received no further communication from FDEP with respect to the site. At this time, we are unable to determine whether additional fieldwork will be required by FDEP and, if so, the scope or costs of such work. In 1999, the Company received an estimate from its consultant that additional costs to assess and remediate the reported impacts would be approximately $166,000. Assuming the current owner shared in such costs according to the allocation agreed upon by the parties for the PCAR, the Company’s share would be approximately $83,000.


11. Commitments


A. General

To ensure a reliable supply of electric and natural gas at competitive prices, the Company has entered into long-term purchase and transportation contracts with various suppliers and producers, which expire at various dates through 2015.  Purchase prices under these contracts are determined by formulas either based on market prices or at fixed prices.  At December 31, 2006, the Company has firm purchase and transportation commitments adequate to supply its expected future sales requirements. The Company is committed to pay demand or similar fixed charges of approximately $37.8 million during 2007 related to gas purchase agreements.  Substantially all costs incurred under the electric and gas purchase agreements are recoverable from customers through fuel adjustment clause mechanisms.


B. Operating Leases

The Company’s total operating lease obligation is $352,000. The Company is leasing property from the City of Fernandina Beach in our Northeast division. The Company is in the process of renegotiating the terms of this lease and it may be able to terminate this lease at an earlier date. The Company leases an appliance showroom in the same division for approximately $35,000 annually. The Company also has other operating lease agreements with various terms and expiration dates. The following table shows the approximate future obligations under noncancelable agreements.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2007

2008

2009

2010

2011

Operating Lease Obligations

$161,000

$116,000

$47,000

$38,000

$        -


12.   Employee Benefit Plans


The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 at December 31, 2006 resulted in an additional liability for retirement plans, pension plan and retirees medical plan. See Footnote 1J, Impact of Recent Accounting Standards, Financial Accounting Standard 158 for a summary of the impact to our financial statements.


A.  Pension Plan

The Company sponsors a qualified defined benefit pension plan for non-union employees that were hired before January 1, 2005 and for unionized employees that work under one of the six Company union contracts and were hired before their respective contract dates in 2005.

 

The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the 3-year period ending December 31, 2006 and a statement of the funded status as of December 31, of all three years:



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit Obligations and Funded Status

 

 

 

Years Ended December 31,

 

 

 

2006

 

2005

 

2004

(1)

Change in Projected Benefit Obligation

 

 

 

 

 

 

(a)

Projected Benefit Obligation at the Beginning of the Year

$36,349,925 

 

$34,926,383 

 

$31,540,942 

 

(b)

Service Cost

1,225,495 

 

1,195,723 

 

1,084,564 

 

(c)

Interest Cost

2,160,719 

 

2,000,099 

 

1,940,122 

 

(d)

Actuarial (Gain) or Loss

541,865 

 

(842,777)

 

1,708,132 

 

(e)

Benefits Paid

(1,529,258)

 

(1,514,341)

 

(1,347,377)

 

(f)

Change in Plan Provisions

- 

 

584,838 

 

- 

 

(g)

Curtailment

(97,858)

 

- 

 

- 

 

(h)

Projected Benefit Obligation at the End of the Year

 $38,650,888 

 

$36,349,925 

 

$34,926,383 

 

(i)

Accumulated Benefit Obligation at the End of the Year

 $33,693,860 

 

$31,966,513 

 

$30,518,393 

(2)

Change in Plan Assets

 

 

 

 

 

 

(a)

Fair Value of Plan Assets at the Beginning of the Year

 $32,936,666 

 

$32,385,214 

 

$31,081,063 

 

(b)

Actual Return on Plan Assets

3,977,806 

 

 2,065,793 

 

 2,651,528 

 

(c)

Benefits Paid

(1,529,258)

 

(1,514,341)

 

(1,347,377)

 

(d)

Employer Contributions

250,000 

 

- 

 

- 

 

(e)

Fair Value of Assets at the End of the Year

$35,635,214 

 

$32,936,666 

 

$32,385,214 

 

 

 

 

 

 

 

(3)

Funded Status: (2)(e) - (1)h)

$(3,015,674)

 

$(3,413,259)

 

 $(2,541,169)

(4)


Amounts Recognized in the Statement of Financial Position

Before Applying FAS 158

 

 

 

 

 

(a)

Prepaid (Accrued) Benefit Cost

$(2,070,740)

 

 $(721,333)

 

$725,619 

 

(b)

Net Asset (liability)

$(2,070,740)

 

 $(721,333)

 

 $725,619 

 

(c)

Charge to Accumulated Other Comprehensive Income:

-

 

-

 

-

(5)

Adjustments Caused by Applying FAS 158

 

(a)

Increase in Net Asset (Liability): (3) – (4)(b)

$(944,934)

 

N/A 

 

N/A 

 

(b)

Increase in Charge to Accumulated Other Comprehensive Income:

207,885 

 

N/A 

 

N/A 

 

(c)

Increase in Charge to Regulatory Asset –retirement plans

737,049 

 

N/A 

 

N/A 

 

(d)

Subtotal of Adjustments: (a)+(b)+(c)

$             - 

 

N/A 

 

N/A 

(6)


Amount Recognized in Statement of Financial Position

After applying FAS 158

 

 

 

 

 

(a)

Net Asset (Liability): (4)(b) + (5)(a)

$(3,015,674)

 

$(721,333)

 

$725,619 

 

(b)

Charge to Accumulated Other Comprehensive Income: (4)(c) + (5)(b)


$207,885 

 


- 

 


- 

 

(c)

Regulatory Asset-Retirement Plans (5) (c)

$737,049 

 

- 

 

- 

(7)


Net Asset (Liability) Recognized in the Statement of Financial Position

After applying FAS 158

 

 

 

 

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Noncurrent Assets

-

 

N/A

 

N/A

 

(b)

(Current Liabilities)

-

 

N/A

 

N/A

 

(c)

(Noncurrent Liabilities)

$(3,015,674)

 

N/A

 

N/A

 

(d)

Total Net Asset (Liability): (a) + (b) + (c)

$(3,015,674)

 

N/A

 

N/A

(8)


Amount Recognized in Accumulated Other Comprehensive Income

And Regulatory Asset –Retirement Plans After applying FAS 158

 

 

 

 

 

(a)

Transition Obligation (Asset)

- 

 

N/A 

 

N/A 

 

(b)

Prior Service Cost (Credit)

$3,992,489 

 

N/A 

 

N/A 

 

(c)

Net (Gain) or Loss

(3,047,555)

 

N/A 

 

N/A 

 

(d)

Total

$944,934 

 

N/A 

 

N/A 

(9)


Weighted Average Assumption at End of Year

 

 

 

 

 

(a)

Discount Rate

6.00%

 

5.90% 

 

5.75% 

 

(b)

Rate of Compensation Increase

3.25%

 

3.15% 

 

3.00% 

 

(c)

Mortality

GAM 83

 

GAM 83

 

GAM 83


The following table provides the components of net periodic benefit cost for the plans for fiscal years 2006, 2005 and 2004:


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Periodic Pension Costs

 

 

 

Years Ended December 31,

 

 

 

2006

 

2005

 

2004

(1)

Service Cost

$1,225,495 

 

$1,195,723 

 

$1,084,564 

(2)

Interest Cost

2,160,719 

 

2,000,099 

 

1,940,122 

(3)

Expected Return on Plan Assets

(2,426,064)

 

(2,485,985)

 

(2,591,099)

(4)

Amortization of Transition Obligation/(Asset)

- 

 

- 

 

- 

(5)

Amortization of Prior Service Cost

737,115 

 

 737,115 

 

698,211 

(6)

Amortization of Net (Gain) or Loss

- 

 

 - 

 

                   - 

(7)

Total FAS 87 Net Periodic Pension Cost

$1,697,265 

 

$1,446,952 

 

$1,131,798 

(8)

FAS 88 Charges / (Credits)

 

 

 

 

 

 

(a)

Curtailment

(97,858)

 

- 

 

- 

(9)

Total Net Periodic Pension Cost and Comprehensive Income

$1,599,407 

 

$1,446,952 

 

$1,131,798 

(10)

Weighted Average Assumptions

 

 

 

 

 

 

(a)

Discount Rate at Beginning of the Period

5.90% 

 

5.75% 

 

6.25% 

 

(b)

Expected Return on Plan Assets

8.50% 

 

8.50% 

 

8.50% 

 

(c)

Rate of Compensation Increase

3.15% 

 

3.00% 

 

3.50% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2007

2006

2005

2004

(1)

Plan Assets

 

 

 

 

 

(a)

Equity Securities

40%-60%

68%

67%

69%

 

(b)

Debt Securities

25%-40%

30%

32%

30%

 

(c)

Real Estate

5%-15%

0%

0%

0%

 

(d)

Other

5%-15%

2%

1%

1%

 

(e)

Total

 

100%

100%

100%


Expected Return on Plan Assets

The expected rate of return on plan assets is 8.5%.  The Company expects 8.5% to fall within the 40 to 50 percentile range of returns on investment portfolios with asset diversification similar to that of the Pension Plan's target asset allocation.


Investment Policy and Strategy

The Company has established and maintains an investment policy designed to achieve a long-term rate of return, including investment income and appreciation, sufficient to meet the actuarial requirements of the Pension Plan.  The Company seeks to accomplish its return objectives by investing in a diversified portfolio of equity, fixed income and cash securities seeking a balance of growth and stability as well as an adequate level of liquidity for pension distributions as they fall due.  Plan assets are constrained such that no more than 10% of the portfolio will be invested in any one issue.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flows

 

 

 

 

 

 

 

(1)

Expected Contributions for Fiscal Year Ending December 31, 2007

 

(a)

Expected Employer Contributions

 

$250,000 

 

(b)

Expected Employee Contributions

 

-

(2)

Estimated Future Benefit Payments Reflecting Expected Future Service for the years ending December 31,

 

 

(a)

2007

 

 

 

 $1,756,069 

 

(b)

2008

 

 

 

 $1,839,843 

 

(c)

2009

 

 

 

 $1,975,656 

 

(d)

2010

 

 

 

 $2,092,003 

 

(e)

2011

 

 

 

 $2,182,628 

 

(f)

2012 – 2016

 

 

 $13,040,794 

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/07

-



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2006

 

2005

 

2004

(1)  

Market-Related Value of Assets as of the Beginning of fiscal year

 $29,290,131

 

 $30,016,761

 

 $31,222,154

(2)


  

Amount of Future Annual Benefits of Plan Participants Covered by Insurance Contracts Issued by the Employer or Related Parties

$ 0

 

$ 0

 

$ 0

(3)  

Alternative Amortization Methods Used to Amortize

 

 

 

 

 

 

(a)

Prior Service Cost

Straight Line

 

Straight Line

 

Straight Line

 

(b)

Unrecognized Net (Gain) or Loss

Straight Line

 

Straight Line

 

Straight Line

(4)

Average Future Service

10.80

 

10.95

 

10.95

(5)

Employer Commitments to Make Future Plan Amendments (that Serve as the Basis for the Employer’s Accounting for the Plan)

None

 

None

 

None

(6)

Description of Special or Contractual Termination Benefits Recognized During the Period

N/A

 

N/A

 

N/A

(7)

Cost of Benefits Described in (6)

N/A

 

N/A

 

N/A

(8)

Explanation of Any Significant Change in Benefit Obligation or Plan Assets not Otherwise Apparent in the Above Disclosures

N/A

 

N/A

 

N/A

(9)

Measurement Date Used

December 31, 2006

 

December 31, 2005

 

December 31, 2004



B.  Medical Plan

The Company sponsors a postretirement medical program.  The medical plan is contributory with participants' contributions adjusted annually.  The following tables provide required financial disclosures over the three-year period ended December 31, 2006:


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit Obligations and Funded Status

 

 

 

Fiscal Year Ending

 

 

 

12/31/2006

 

12/31/2005

 

12/31/2004

(1)

Change in Accumulated Postretirement Benefit Obligation

 

 

 

 

 

 

(a)

Accumulated Postretirement Benefit Obligation at the Beginning of the Year

 $2,343,583 

 

 $1,925,254 

 

 $1,807,999 

 

(b)

Service Cost

 59,982 

 

 100,054 

 

 70,300 

 

(c)

Interest Cost

 105,483 

 

 127,312 

 

 106,079 

 

(d)

Actuarial (Gain) or Loss

 (568,755)

 

 282,812 

 

          32,646 

 

(e)

Benefits Paid

 (117,459)

 

 (135,166)

 

 (119,005)

 

(f)

Change in Plan Provisions

  - 

 

  - 

 

  - 

 

(g)

Plan Participant's Contributions

 42,519 

 

 43,317 

 

 27,235 

 

(h)

Accumulated Postretirement Benefit Obligation at the End of the Year

 $1,865,353 

 

 $2,343,583 

 

 $1,925,254 

(2)

Change in Plan Assets

 

 

 

 

 

 

(a)

Fair Value of Plan Assets at the Beginning of the Year

 $ - 

 

 $ - 

 

 $ - 

 

 

 

 

 

 

 

 

 

(b)

Benefits Paid

 (117,459)

 

 (135,166)

 

 (119,005)

 

(c)

Employer Contributions

 74,940 

 

 91,849 

 

 91,770 

 

(d)

Plan Participant's Contributions

 42,519 

 

 43,317 

 

 27,235 

 

(e)

Fair Value of Assets at the End of the Year

 $ - 

 

 $ - 

 

 $ - 

(3)

Net Amount Recognized

 

 

 

 

 

 

(a)

Funded Status: (2)(e) - (1)(h)

$(1,865,353)

 

$(2,343,583)

 

$(1,925,254)

(4)

Amounts Recognized in the Statement of Financial Position Before Applying FAS 158

 

 

 

 

 

 

(a)

Prepaid (Accrued) Benefit Cost

(2,057,833)

 

(1,942,393)

 

(1,763,980)

 

(b)

(Additional Liability due to an Unfunded ABO)

-

 

-

 

-

 

(c)

Intangible Asset

-

 

-

 

-

 

(d)

Net Asset (Liability):  (a) + (b) + (c)

$(2,057,833)

 

$(1,942,393)

 

$(1,763,980)

 

(e)

Charged to Accumulated Other Comprehensive Income:

-

 

-

 

-

(5)

Adjustments Caused by Applying FAS 158

 

 

 

 

 

 

(a)

Increase in Net Asset (Liability): (3) – (4)(d)

$192,480

 

N/A

 

N/A

 

(b)

Increase in charge to Accumulated Other Comprehensive Income:

(42,346)

 

N/A

 

N/A

 

(c)

Increase in charge to Regulatory Asset-retirement plans

(150,134)

 

N/A

 

N/A

 

(d)

Subtotal of Adjustments: (a) + (b) + (c)

$ - 

 

N/A

 

N/A

(6)

Amounts Recognized in the Statement of Financial Position After applying FAS 158

 

 

 

 

 

 

(a)

Net Asset (Liability): (4)(d) +(5)(a)

(1,865,353)

 

(1,942,393)

 

(1,763,980)

 

(b)

Charge to Accumulated Other Comprehensive Income: (4)(e) + (5)(b)

(42,346)

 

-

 

-

 

(c)

Charge to Regulatory Asset-Retirement Plans (5)(c)

(150,134)

 

-

 

-

(7)

Net Asset (Liability) Recognized in the Statement of Financial Position After Applying FAS 158

 

 

 

 

 

 

(a)

Noncurrent Assets

$ -

 

N/A

 

N/A

 

(b)

(Current Liabilities)

(150,589)

 

N/A

 

N/A

 

(c)

(Noncurrent Liabilities)

(1,714,764)

 

N/A

 

N/A

 

(d)

Total Net Asset (Liability): (a) + (b) + (c)

$(1,865,353)

 

N/A

 

N/A

(8)

Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Asset After Applying FAS 158

 

 

 

 

 

 

(a)

Transition Obligation (Asset)

$ -

 

N/A

 

N/A

 

(b)

Prior Service Cost (Credit)

-

 

N/A

 

N/A

 

(c)

Net (Gain) or Loss

(192,480)

 

N/A

 

N/A

 

(d)

Total

$(192,480)

 

N/A

 

N/A

(9)

Weighted Average Assumptions at the End of the Year

 

 

 

 

 

 

(a)

Discount Rate

6.00% 

 

5.90% 

 

5.75% 

 

(b)

Rate of Compensation Increase

N/A 

 

N/A 

 

N/A 

 

(c)

Mortality

GAM 83

 

GAM 83

 

GAM 83

(10)

Assumed Health Care Cost Trend Rates

 

 

 

 

 

 

(a)

Health Care Cost Trend Rate Assumed for Next Year

11.50% 

 

9.00% 

 

10.00% 

 

(b)

Ultimate Rate

5.00% 

 

5.00% 

 

5.00% 

 

(c)

Year that the Ultimate Rate is Reached

2014 

 

2010 

 

2010 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Periodic Postretirement Benefit Cost


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

 

 

 

2006

 

2005

 

2004

(1)

Service Cost

 $59,982 

 

 $100,054 

 

 $70,300 

(2)

Interest Cost

 105,483 

 

 127,312 

 

 106,079 

(3)

Amortization of Transition Obligation/(Asset)

 42,896 

 

 42,896 

 

 42,896 

(4)

Amortization of Prior Service Cost

-

 

-

 

-

(5)

Amortization of Net (Gain) or Loss

 (17,981) 

 

             -

 

(8,666)

(6)

Total Net Periodic Benefit Cost

 $190,380 

 

 $270,262 

 

 $210,609 

(7)

Weighted Average Assumptions

 

 

 

 

 

 

(a)

Discount Rate

5.90% 

 

5.75% 

 

6.25% 

 

(b)

Expected Return on Plan Assets

N/A 

 

N/A 

 

N/A 

 

(c)

Rate of Compensation Increase

N/A 

 

N/A 

 

N/A 

(8)

Assumed Health Care Cost Trend Rates

 

 

 

 

 

 

(a)

Health Care Cost Trend Rate Assumed for

12.50% 

 

10.00% 

 

12.00% 

 

 

Current Year

 

 

 

 

 

 

(b)

Ultimate Rate

5.00% 

 

5.00% 

 

5.00% 

 

(c)

Year that the Ultimate Rate is Reached

2014 

 

2010 

 

2010 

 

Expected Amortizations

 

 

 

Years ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Expected Amortization of Transition Obligation (Asset)

-

 

N/A

 

N/A

 

 

 

 

 

 

 

 

(2)

Expected Amortization of Prior Service Cost (Credit)

-

 

N/A

 

N/A

(3)

Expected Amortization of Net Loss (Gain)

$(536)

 

N/A

 

N/A

(9)

Impact of One-Percentage-Point Change in

 

 

 

 

 

 

Assumed Health Care Cost Trend Rates

Increase 

 

Decrease 

 

 

 

(a)

Effect on Service Cost + Interest Cost

$20,533 

 

$(17,812)

 

 

 

(b)

Effect on Postretirement Benefit Obligation

$203,809 

 

$(179,005)

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2007

2006

2005

2004

(1)

Plan Assets

 

 

 

 

 

(a)

Equity Securities

N/A

N/A

N/A

N/A

 

(b)

Debt Securities

N/A

N/A

N/A

N/A

 

(c)

Real Estate

N/A

N/A

N/A

N/A

 

(d)

Other

N/A

N/A

N/A

N/A

 

(e)

Total

N/A

N/A

N/A

N/A



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flows

 

 

 

 

 

 

 

(1)

Expected Contributions for Fiscal Year Ending 12/31/2007

 

 

 

(a)

Expected Employer Contributions

 

 

 $150,589

 

(b)

Expected Employee Contributions

 

 

 $48,832

 

 

 

 

 

 

(2)

Estimated Future Benefit Payments Reflecting Expected Future Service for the Fiscal Year(s) Ending

 

 

 

 

 

 

 

Total

Medicare Part-D Reimbursement

Employee

Employer

 

(a)

12/31/2007

 $199,421 

 $0 

 $48,832 

 $150,589 

 

(b)

12/31/2008

 $143,659 

 $8,266 

 $36,130 

 $99,263 

 

(c)

12/31/2009

 $146,580 

 $8,749 

 $36,535 

 $101,296 

 

(d)

12/31/2010

 $160,560 

 $9,504 

 $41,759 

 $109,297 

 

(e)

12/31/2011

 $199,681 

 $10,062 

 $51,049 

 $138,570 

 

(f)

12/31/2012 – 12/31/2016

 $1,407,957 

 $61,062 

 $350,375 

 $996,520 

 

 

 

 

 

 

 

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/07

$0



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2006

 

2005

 

2004


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Market-Related Value of Assets

 N/A

 

 N/A

 

 N/A

(2)

Amount of Future Annual Benefits of Plan Participants Covered by Insurance Contracts Issued by the Employer or Related Parties

-

 

-

 

-

(3)

Alternative Amortization Methods Used to Amortize

 

 

 

 

 

 

(a)

Prior Service Cost

Straight Line

 

Straight Line

 

Straight Line

 

(b)

Unrecognized Net (Gain) or Loss

Straight Line

 

Straight Line

 

Straight Line

(4)

Average Future Service

11.10

 

13.35

 

12.48

(5)

Employer Commitments to Make Future Plan Amendments (that Serve as the Basis for the Employer’s Accounting for the Plan)

None

 

None

 

None

(6)

Description of Special or Contractual Termination Benefits Recognized During the Period

N/A

 

N/A

 

N/A

(7)

Cost of Benefits Described in (6)

N/A

 

N/A

 

N/A

(8)

Explanation of Any Significant Change in Benefit Obligation or Plan Assets not Otherwise Apparent in the Above Disclosures

N/A

 

N/A

 

N/A

(9)

Measurement Date Used

December 31, 2006

 

December 31, 2005

 

December 31, 2004


Discount Rate Assumption

The discount rate assumption used to determine the postretirement benefit obligations is based on current yield rates in the double A bond market.  The current year’s discount rate was selected using a method that matches projected payouts from the plan with a zero-coupon double A bond yield curve.  This yield curve was constructed from the underlying bond price and yield data collected as of the plan’s measurement date and is represented by a series of annualized, individual discount rates with durations ranging from six months to thirty years.  Each discount rate in the curve was derived from an equal weighting of the double A or higher bond universe, apportioned into distinct maturity groups.  These individual discount rates are then converted into a single equivalent discount rate, which is then used for FAS discount purposes.  To assure that the resulting rates can be achieved by a postretirement benefit plan, only bonds that satisfy certain criteria and are expected to remain available through the period of maturity of the plan benefits are used to develop the discount rate.  Prior years’ discount rate assumptions were set based on investment yields available on double A, long-term corporate bonds.


Actuarial Equivalent

In determining "Actuarial Equivalence," our plan’s actuary, Aon Consulting, proprietary prescription drug pricing tool, Aon Rx, was used.  This tool allowed us to determine the estimated Per Member Per Month (PMPM) prescription drug cost for both the Company plan and the Medicare plan.  The two PMPM's were adjusted for monthly retiree contributions.  We assumed that 60% of the monthly combined medical and prescription drug retiree contribution for the Company plan applies towards prescription drugs.



Voluntary Prescription Drug Coverage

Legislation enacted in December 2003 provides for the addition of voluntary prescription drug coverage under Medicare starting in 2006.  The legislation also provides for a 28% tax-free subsidy for each qualified covered retiree’s drug cost between certain thresholds if the employer’s coverage is at least actuarially equivalent to the standard Medicare drug benefit.  Based on the final regulations issued by the Centers for Medicare and Medicaid Services on January 21, 2005, we determined our prescription drug coverage of the Postretirement Medical Benefits plan to be actuarially equivalent to Medicare Part D.


C. Health Plan

In December 2003, the Company became fully insured for its employee and retiree’s medical insurance. Net health care benefits paid by the Company for active employees were approximately $1.7 million in 2006, $1.6 million in 2005 and $1.5 million in 2004, excluding administrative and stop-loss insurance.


D. 401K Plan

The Company has discontinued eligibility to the defined benefit pension plan for all new hires, and replaced it with a new 401K match.


For new hires not eligible for the defined benefit pension plan, we established an employer match to the employee’s contribution to their 401K plans. It provided for a company match of 50% for each dollar contributed by the employee, up to 6% of their salary, for a Company contribution of up to 3%. Beginning in 2007, for non-union employees the plan was enhanced to provide a company match of 100% for the first 2% of an employee’s contribution, and a match of 50% for the next 4% of an employee’s contribution, for a total company match of up to 4%. This new enhanced match will be negotiated with our six union contracts during 2007, to be effective on their respective contract date within 2007. The employees are eligible for the company match after six months of continuous service, with vesting of 100% after three years of continuous service.  The expenses incurred in 2005 and 2006 relating to the Company’s 401K plan are not material.


E. Employee Stock Purchase Plan

The Company offers an employee stock purchase plan to substantially all of its employees.  The plan offers a 15% discount on the Company’s stock at market price fixed six months prior to the date of purchase.  The recorded stock compensation expense relating to the Company’s employee stock purchase plan is not material.



13.   Segment Information


The Company is organized into two regulated business segments: natural gas and electric, and one non-regulated business segment, propane gas.  There are no material inter-segment sales or transfers.


Identifiable assets are those assets used in the Company’s operations in each business segment.  Common assets are principally cash and overnight investments, deferred tax assets and common plant.


Business segment information for 2006, 2005 and 2004 is summarized as follows:


 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands)

 

2006

 

2005

 

2004

Revenues

 

 

 

 

 

 

Natural gas

$

71,139 

$ 

69,094 

$ 

55,962 

Electric

 

48,527 

 

47,450 

 

42,910 

Propane gas

 

14,727 

 

13,479 

 

11,167 

Consolidated

$

134,393 

$ 

130,023 

$ 

110,039 

Operating income, excluding income tax

 

 

 

 

 

 

Natural gas

$

6,118 

$ 

6,049 

$ 

4,978 

Electric

 

3,053 

 

3,502 

 

3,353 

Propane gas

 

1,006 

 

1,086 

 

655 

Consolidated

$

10,177 

$ 

10,637 

$ 

8,986 

Identifiable assets

 

 

 

 

 

 

Natural gas

$

93,689 

$ 

96,106 

$ 

87,729 

Electric

 

52,251 

 

51,317 

 

48,687 

Propane gas

 

19,239 

 

19,567 

 

15,731 

Common

 

15,734 

 

15,676 

 

18,356 

Consolidated

$

180,913 

$ 

182,666 

$ 

170,503 

Depreciation and amortization

 

 

 

 

 

 

Natural gas

$

4,095 

$ 

3,928 

$ 

2,752 

Electric

 

2,610 

 

2,404 

 

2,323 

Propane gas

 

720 

 

621 

 

560 

Common

 

317 

 

313 

 

265 

Consolidated

$

7,742 

$ 

7,266 

$ 

5,900 

Construction expenditures

 

 

 

 

 

 

Natural gas

$

7,643 

$ 

6,357 

$ 

5,314 

Electric

 

3,184 

 

3,775 

 

6,793 

Propane gas

 

1,885 

 

2,133 

 

1,339 

Common

 

404 

 

176 

 

285 

Consolidated

$

13,116 

$ 

12,441 

$ 

13,731 

Income tax expense

 

 

 

 

 

 

Natural gas

$

1,336 

$ 

1,283 

$ 

843 

Electric

 

546 

 

666 

 

565 

Propane gas

 

110 

 

245 

 

130 

Common

 

246 

 

93 

 

77 

Consolidated

$

2,238 

$ 

2,287 

$ 

1,615 




14.   Quarterly Financial Data (Unaudited)


The quarterly financial data presented below reflects the influence of seasonal weather conditions, the timing of rate increases and the migration of winter residents and tourists to Central and South Florida during the winter season. Significant increases in the fourth quarter of 2005 expenses relate to the performance of previously delayed expenditures from previous quarters.



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands, except per share amounts):

First Quarter

Second Quarter

Third Quarter *

Fourth Quarter

2006

 

 

 

 

 

 

 

 

Revenues

$

43,348 

$ 

29,878 

$ 

29,415 

$ 

31,752  

Gross profit

$

14,135 

$ 

11,402 

$ 

10,867 

$ 

12,018  

Operating income

$

4,528 

$ 

2,065 

$ 

1,263 

$ 

2,321 

Earnings before income taxes

$

3,507 

$ 

1,162 

$ 

          384 

$ 

1,354 

Net Income

$

2,221 

$ 

738 

$ 

335 

$ 

875 

Earnings per common share (basic and diluted):

 

 

 

 

 

 

 

 

Continuing operations

$

 0.37 

$ 

0.12 

$ 

0.05 

$ 

0.14 

 

 

 

 

 

 

 

 

 

2005

 

 

 

 

 

 

 

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

35,438 

$ 

28,329 

$ 

29,190 

$ 

37,066 

Gross profit

$

13,619 

$ 

10,963 

$ 

10,374 

$ 

12,263 

Operating income

$

4,684 

$ 

2,215 

$ 

1,578 

$ 

2,160 

Earnings before income taxes

$

3,711 

$ 

1,205 

$ 

          573 

$ 

1,046 

Net Income

$

2,353 

$ 

851 

$ 

260 

$ 

784 

Earnings per common share (basic and diluted):

 

 

 

 

 

 

 

 

Continuing operations

$

 0.40 

$ 

0.14 

$ 

0.04 

$ 

0.13 

 

 

 

 

 

 

 

 

 


* The third quarter of 2006 has been restated and revised for pension expense and income tax expense to reflect a correction of the valuation of our pension liability. The pension liability and expense increased by $225,000 and the deferred tax expense and deferred tax liability decreased by $85,000 in the third quarter of 2006. The following summary shows the effect on our financial statements.


Summary of Third Quarter 2006 Adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Dollars in thousands, except per share amounts):

 Third

Quarter Before Revision

Adjustment

Third Quarter

 After Revision

2006

 

 

 

 

 

 

Revenues

$

29,415 

 

-

$ 

29,415 

Gross profit

$

10,867 

 

-

$ 

10,867 

Operating income

$

     1,488

 

(225)

$ 

1,263 

Earnings before income taxes

$

        609

 

(225)

$ 

          384 

Net Income

$

        475

 

(140)

$ 

335 

Earnings per common share (basic and diluted):

 

 

 

 

 

 

Continuing operations

$

      0.08

 

(.03)

$ 

0.05 

 

 

 

 

 

 

 



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Directors and Shareholders of FPU:


We have audited the accompanying consolidated balance sheets and statements of capitalization of Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation as of December 31, 2006 and 2005 and the related consolidated statements of income, comprehensive income, common shareholders' equity and cash flows for each of the three years in the period ended December 31, 2006.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these 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.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and schedules, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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 Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation at December 31, 2006 and 2005, and the results of its operation and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.  


As discussed in Notes 1J and 12 to the consolidated financial statements, on December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158 "Employers' Accounting for Defined Benefit Pensions and Other Postretirement Benefit Plans."



BDO Seidman, LLP

Certified Public Accountants

West Palm Beach, Florida

March 16, 2007


Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


None


Item 9A.   Controls and Procedures


Disclosure Controls and Procedures

Our management carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2006, our disclosure controls and procedures were effective, in that they provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.


Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


Item 9B.   Other Information


None


PART III


Item 10.    Directors and Executive Officers of the Registrant


Information required by this item concerning directors and nominees of the Registrant will be included under the caption "Information About Nominees and Continuing Directors" in the Registrant's Proxy Statement for the 2007 Annual Meeting of Shareholders (the “2007 Proxy Statement”) and is incorporated by reference herein.  Information required by this item regarding the Audit Committee will be included under the caption “Board of Directors and Committees” in the 2007 Proxy Statement and is incorporated by reference herein.  Information required by this Item regarding the Code of Ethics will be included under the caption “Code of Ethics” in the 2007 Proxy Statement and is incorporated by reference herein.  Information required by this Item regarding compliance with Section 16(a) of the Exchange Act will be set forth in the 2007 Proxy Statement under “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated by reference herein. Information required by this Item concerning executive officers is set out in Part I of this Form 10-K, above.


Item 11.   Executive Compensation


Information required by this Item concerning executive compensation is included under the captions “Board of Directors and Committees”, "Executive Compensation", and “Compensation Committee Interlocks and Inside Participation” in the 2007 Proxy Statement is incorporated by reference herein.


Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


Information required by this Item concerning the security ownership of certain of the Registrant's beneficial owners and management is included under the caption "Security Ownership of Management and Certain Beneficial Owners" in the 2007 Proxy Statement and is incorporated by reference herein.  See Item 5 above for equity compensation plan information, which is incorporated by reference herein.


Item 13.   Certain Relationships and Related Transactions


None.


Item 14.   Principal Accountant Fees and Services


Information required by this Item is set forth in the Registrant’s 2007 Proxy Statement under the caption “Principal Accountant Fees and Services” and is incorporated by reference herein.



PART IV



Item 15.   Exhibits, Financial Statement Schedules


(a)    The following documents are filed as part of this report:


(1)   Financial Statements

The following consolidated financial statements of the Company are included herein and in the Registrant's 2006 Annual Report to Shareholders:


Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Capitalization

Consolidated Statements of Common Shareholders' Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm


(2)   Financial Statement Schedules

The following valuation and qualifying accounts table is included in Note 1.H. herein and in the Registrant’s 2006 Annual Report to Shareholders:


Allowance for Doubtful Accounts


(3)   Exhibits



3(i) Amended Articles of Incorporation (Incorporated herein by reference as Exhibit 3(i) to FPU’s quarterly report on Form 10-Q for the period ended June 30, 2002. SEC File No. 1-10608)


3(ii) Amended By-Laws (Incorporated herein by reference as Exhibit 3(ii) to FPU’s quarterly report on Form 10-Q for the period ended June 30, 2002. SEC File No. 1-10608)


4(a) Indenture of Mortgage and Deed of Trust of FPU dated as of September 1, 1942 (Incorporated by reference herein to Exhibit 7-A to Registration No. 2-6087)


4(b) Fourteenth Supplemental Indenture dated September 1, 2001. (Incorporated by reference to exhibit 4(b) on FPU’s annual report on Form 10-K for the year ended December 31, 2001)


4(c) Fifteenth Supplemental Indenture dated November 1, 2001. (Incorporated by reference to exhibit 4(c) on FPU’s annual report on Form 10-K for the year ended December 31, 2001)


10(a) First Amendment to Amended and Restated Loan Agreement and Promissory Note between FPU and Bank of America dated August 25, 2006. (Incorporated by reference to exhibit 10(2) on FPU’s Form 10-Q for third quarter ending September 30, 2006, File No. 001-10608)


10(b) Contract for the transportation of natural gas between FPU and the City of Lake Worth dated March 25, 1992 (Incorporated by reference to exhibit 10(f) on FPU’s Form S-2 for July 1992, File No. 0-1055)


10(c) Contract for the purchase of electric power between FPU and Jacksonville Electric Authority dated January 29, 1996. (Incorporated by reference to exhibit 10(h) on FPU’s annual report on Form 10-K for the year ended December 31, 2000)


10(d) Contract for the purchase of electric power between FPU and Gulf Power Company effective November 21, 1996. (Incorporated by reference to exhibit 10(i) on FPU’s annual report on Form 10-K for the year ended December 31, 2000)


10(e) Contract for the purchase of as-available capacity and energy between FPU and Container Corporation of America dated September 19, 1985 (Incorporated by reference to exhibit 10(i) on FPU’s Form S-2 for July 1992, File No. 0-1055)


10(f) Contract for the sale of electric service between FPU and Container Corporation of America dated August 26, 1982 (Incorporated by reference to exhibit 10(j) on FPU’s Form S-2 for July 1992, File No. 0-1055)


10(g) Contract for the sale of electric service between FPU and ITT Rayonier Inc. Dated April 1, 1982 (Incorporated by reference to exhibit 10(k) on FPU’s Form S-2 for July 1992, File No. 0-1055)


10(h) Form of Stock Purchase and Sale Agreement between FPU and three persons who, upon termination of two trusts, will become the record and beneficial owners of an aggregate of 313,554 common shares of the Registrant (Incorporated by reference to exhibit 10(p) on FPU’s Form S-2 for July 1992, File No. 0-1055)


10(i) Contract for the sale of certain assets comprising FPU’s water utility business to the City of Fernandina Beach dated December 3, 2002. Incorporated by reference to exhibit 10(o) on FPU’s annual report on Form 10-K for the year ended December 31, 2002)


10(j) Transportation agreement between FPU and the City of Lake Worth (Incorporated by reference to exhibit 99.2 on FPU’s Form 8-K filed April 4, 2003, File No. 001-10608)


10(k) A Mutual Release agreement, as of March 31, 2003, by and between FPU, Lake Worth Generation, LLC, The City of Lake Worth, and The AES Corporation. (Incorporated by reference to exhibit 99.3 on FPU’s Form 8-K filed April 4, 2003, File No. 001-10608)


10(l) Amended and Restated loan agreement between FPU and Bank of America, N.A. dated October 29, 2004.  (Incorporated by reference as exhibit 10(n) on FPU’s annual report on Form 10-K for the year ended December 31, 2004)


10(m) Security agreement between FPU and Bank of America, N.A. dated October 29, 2004.  (Incorporated by reference as exhibit 10(o) on FPU’s annual report on Form 10-K for the year ended December 31, 2004)


10(n) # Non-Employee Director Compensation Plan, approved by Board of Directors on March 18, 2005.  (Incorporated by reference as exhibit 10(p) on FPU’s annual report on Form 10-K for the year ended December 31, 2004)


10(o) Amendment to Electric Service Contract by and between JEA and FPU dated September 25, 2006, effective January 1, 2007. (Incorporated by reference as Exhibit 10.1 to our Form 10-Q, for the quarter ending September 30, 2006, File No. 001-10608)


10(p) # Employment Agreement between the Company and John T. English dated March 31, 2006 (Incorporated by reference as Exhibit 10.1 to our Form 8-K, filed on March 31, 2006)


10(q) # Employment Agreement between the Company and Charles L. Stein dated March 31, 2006 (Incorporated by reference as Exhibit 10.2 to our Form 8-K, filed on March 31, 2006)


10(r) # Employment Agreement between the Company and George M. Bachman dated March 31, 2006 (Incorporated by reference as Exhibit 10.3 to our Form 8-K, filed on March 31, 2006)


10(s) * Contract for the Agreement for Generation Services by and between FPU and Gulf Power Company dated December 28, 2006, effective January 1, 2008


14 Ethics Policy (Incorporated by reference to exhibit 99.3 on FPU’s Form 10-K, filed March 30, 2004 File No. 001-10608)


16 Change in certifying accountants (Incorporated herein by reference as exhibit 16 to FPU’s current report on Form 8-K, filed April 18, 2003)


21 Subsidiary of the registrant (Incorporated by reference to exhibit 21 on FPU’s annual report on Form 10-K, for the year ended December 31, 2000)


23 Independent Registered Public Accounting Firm’s Consent BDO Seidman LLP


31.1 Certification of Principal Executive Officer (302)


31.2 Certification of Principal Financial Officer (302)


32 Certification of Principal Executive Officer and Principal Financial Officer (906)



#  Denotes management contract or compensatory plan or arrangement


*  Confidential treatment is being requested for a portion of this agreement 


SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


FLORIDA PUBLIC UTILITIES COMPANY



       /s/ George M Bachman

 

George M Bachman, Chief Financial Officer

(Duly Authorized Officer)


Date: March 19, 2007


Each person whose signature appears below hereby constitutes and appoints John T. English, Chief Executive Officer and President, and George M. Bachman, Chief Financial Officer, and each of them, the true and lawful attorneys-in-fact and agents of the undersigned, with full power undersigned, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and hereby grants to such attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue thereof.


/s/ John T. English

Date:  March 19, 2007

John T. English

Chairman of the Board, President, Chief Executive Officer, and

Director (Principal Executive Officer)


/s/ George M. Bachman

Date:  March 19, 2007

George M Bachman, Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)


/s/ Ellen Terry Benoit

Date:  March 19, 2007

Ellen Terry Benoit, Director


/s/ Richard C. Hitchins

Date:  March 19, 2007

Richard C. Hitchins, Director


/s/ Dennis S. Hudson III

Date:  March 19, 2007

Dennis S. Hudson III, Director


/s/ Paul L. Maddock, Jr.

Date:  March 19, 2007

Paul L. Maddock, Jr., Director


/s/ Troy W. Maschmeyer, Jr.        Date:  March 19, 2007

Troy W. Maschmeyer, Jr., Director



FLORIDA PUBLIC UTILITIES COMPANY

EXHIBIT INDEX

Regulation S-K

Item Number


10(s) * Contract for the Agreement For Generation Services by and between FPU and Gulf Power Company dated December 28, 2006, effective January 1, 2008


23 Independent Registered Public Accounting Firm’s Consent BDO Seidman LLP


31.1 Certification of Principal Executive Officer (302)


31.2 Certification of Principal Financial Officer (302)


32 Certification of Principal Executive Officer and Principal Financial Officer (906)



*   Confidential treatment is being requested for a portion of this agreement