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Florida Public Utilities Company 10-K 2006
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, 2005

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


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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, 2005, 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 $71,400,000.


On February 17, 2006, 5,980,037 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 9, 2006 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 81,000 customers, and our unregulated segment sells propane 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 Palm Beach, Martin and Broward Counties

(2)

Central Florida Division - provides natural and propane gas to customers in Lake, Seminole, Orange, Flagler and Volusia Counties

(3)

Northwest Florida Division - provides electricity to customers in Jackson, Calhoun and Liberty Counties

(4)

Northeast Florida Division - provides electricity and propane gas to customers in Duval and Nassau Counties

(5)

West Florida Division - provides propane gas to customers in Levy, Citrus, Hernando, Marion and Pasco Counties


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 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 seen dramatic increases in 2005 in part due to the effects of hurricane Katrina on gas supplies.  Moderate winter weather may have assisted in keeping prices lower than originally expected for this winter season; however, prices still remain higher than the previous winter. Prices are also directly affected by global energy prices. We are unable to determine the effects, if any, that this may have on demand for gas and future operating results.





Industry electric prices have also been impacted since natural gas is used in varying degrees in the generation of electricity. As a result, 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 long-term favorable fixed price contracts for purchasing electricity.  However, our contracts expire at the end of 2007 and our electric prices are expected to significantly increase to close to market prices in 2008. 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.


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 holding workshops to determine what can be done to improve electric reliability. Increased utility regulation in the form of rule making is currently underway regarding pole inspections, strengthened design specifications for wind loading, vegetation management practices and installation of underground facilities for electric distribution and transmission systems.  The Company is able to comply with current reliability standards and expects to be able to comply with all future reliability regulation.


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 areas to complement these segments. For information concerning revenues, operating income and identifiable assets of each of our segments, see Note 14 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 one to readily detect 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.  Although there were reductions in natural gas supplies as a result of the recent hurricanes, we did not experience any shortages during those hurricanes. We were able to obtain supplies from areas that were not affected by the hurricanes.


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 independently to procure all gas supplies for our markets.  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. The weather can result in higher gas sales per day during the winter period when gas is used for heating.  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 customers 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 revenue.


We have signed a letter of intent and are in negotiations for a natural gas territorial agreement with Indiantown Gas for a location adjacent to and within its service area. The FPSC is aware of and supports this agreement.  Significant residential development is planned for Indiantown in Martin County. We plan to transport natural gas through Indiantown’s system to new developments. In the early phase, Indiantown Gas will provide operational and customer service related work. Development is expected to begin in 2006.  We do not anticipate any significant increase in the number of customers or revenues during 2006, but both should increase as the development continues. Early estimates for this area indicate the number of customers may increase by 7,500 over the next ten years.


Electric

We provide electricity in our Northwest and Northeast divisions to customers in Jackson, Calhoun, Liberty and Nassau Counties in Florida.  Wholesale electricity is purchased from two suppliers, Southern Company and JEA (formerly Jacksonville Electric Authority).  In 1996, we executed long-term fixed-price purchased power contracts with both suppliers that will continue through 2007.  Southern Company provides electric power to the Northwest division and JEA provides electric power to the Northeast division.  Less than 1% of our power supply is purchased on an as-available basis from a self-generating paper mill in Fernandina Beach, located in our Northeast division.  These long-term contracts provide our customers with the lowest consumer electric rates in Florida.


We have completed requests for proposals for new electric supply contracts, and have entered into negotiations with suppliers that were selected for new electricity contracts.  During 2006 we anticipate completion of final contracts for the supply of our electricity beginning January 1, 2008. We expect that rates charged to our customers will significantly increase to closer to market when the new contracts become effective in 2008. 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 purchase our propane 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. We believe that the propane gas supply infrastructure is adequate to meet the needs of the industry in Florida for the foreseeable future.




Although there were disruptions in the propane supply stream as a result of the recent hurricanes, we did not experience any shortages during those hurricanes. We were able to utilize our storage assets and obtain supplies from areas that were not affected by the hurricanes.


Propane gas is not as affected by environmental regulations as other petroleum products.  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. Propane sales during this period are affected by tourism and the weather.  The propane 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 sales volume or revenues.


Strategy

Our strategy is to leverage our expertise in the natural gas, electric and propane gas distribution business with an emphasis on 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 of our electric divisions. Although our natural gas segment operates with the same types of guidelines, there is competition in our natural gas segment from the electric utilities. Normally each home will have electricity as a base fuel; natural gas is an alternative second source of energy used in the home for cooking and heating. Electricity is an alternative source of energy that 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 customer 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 subject to federal and state regulation 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.


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 FEDP 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 24, 2006, we had 352 employees, of which 9 were part-time and 7 were temporary. Of these employees, 171 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). These reports and 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.


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 Florida Gas Transmission Company 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 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 business competes directly with other distributors of propane, and other sources of energy including natural gas and electric.  We cannot assure you that we will not 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 CrossCountry 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.


Our segments are sensitive to variations in weather.


Most of 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 customers use our gas primarily for heating purposes.  As a result, our natural gas and propane 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 operations. Severe weather conditions could also interrupt or slow down service and increase operating costs of all our segments.


Our electricity and natural gas businesses are highly regulated and any changes in regulatory structures could lower revenues, lower profits or increase costs or competition.


Our electricity and natural gas segments are highly regulated. Our electric and natural gas operations, including the prices charged, are regulated by the FPSC. Changes in regulatory requirements or adverse regulatory actions could have a material adverse effect on our financial condition and results of operations by, for example, increasing competition or costs, threatening investment recovery or impacting rate structure.


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


Most of 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 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.  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 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 both expire in 2007.  If we were to lose any of these contracts, we may 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 may not be able to renew them on favorable terms, if at all.  As a result, the loss of any of these suppliers, the termination of any of these supply contracts or the non-renewal of any of these supply contracts upon their expiration could have a material adverse effects on our financial condition and results of operations.


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, 2005, we have firm purchase and transportation commitments adequate to supply our expected sales requirements for electricity through 2007. 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 acquisition and 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 these acquisition and 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.


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


We cannot assure you 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 you from receiving a takeover premium for your 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.


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 1,519 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 1,073 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 19 community gas systems that distribute propane 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 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.  See Note 8 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 any 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 Florida Department of Environmental Protection (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.  On November 29, 2005, our consultant submitted a status report of additional sampling to FDEP, in which the consultant recommended that we should be permitted to proceed with a feasibility study to evaluate appropriate remedies for the site.  To date, FDEP has not responded to the status report.


Sanford Site

We own a parcel of property located in Sanford, Florida. A gasification plant was operated on this site prior to our acquisition of the property.  Following discovery of soil and groundwater impacts on the property, we 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 and Feasibility Study (RI/FS) task and to pay EPA’s past and future oversight costs for the RI/FS.  The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (RI/FS Participation Agreement). These agreements governed the manner and means by which all parties were to satisfy their respective obligations under the AOC for the RI/FS task.  We agreed to pay approximately 13.7% of the cost for the RI/FS.  Our share of the cost of these tasks was previously paid in full.  The RI/FS Participation Agreement was amended on September 18, 2003, to authorize an additional $400,000 to be incurred by the Group to complete the ecological risk assessment and cover EPA oversight costs for the RI/FS.  We paid our share ($54,822) of the additional RI/FS funding in November 2003.


On July 5, 2000, EPA issued a Record of Decision (ROD) approving the final remedial action for contaminated soils at the site (OU1 Remedy). The initial estimated cost for the OU1 Remedy described in the ROD ranges from $5.6 million to $5.8 million.  On June 12, 2001, EPA issued a ROD approving the final remedial action for contaminated groundwater



 at the site (OU2 Remedy).  The present worth cost estimate for the OU2 Remedy is $320,252.


We are a party to the Second Participation Agreement entered into by members of the Group on August 1, 2000, as amended through June 19, 2002 (RD/RA Participation Agreement).  The RD/RA Participation Agreement provides for funding the remedial design/remedial action (RD/RA) task for OU1 and OU2.  Our share of costs for implementation of the RD/RA task for OU1 and OU2, including the pre-remedial design fieldwork is 10.5%, providing the total cost of the RD/RA task, including the pre-remedial design fieldwork, does not exceed $6 million.


Pensacola site

We are the prior owner and 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.


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 would defer management of the site to FDEP; however, as of this date, we have not received any written confirmation from EPA or FDEP regarding this matter.


Key West site

From 1927 to 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 (SEA) 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.  To date, we have received no further communication from FDEP with respect to the site.





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, 2006.


 

Name

Age

Position

Date


John T. English

62

Chief Executive Officer

1998 - Present

President

1997 - Present

Chief Operating Officer

1997 - 2000


Charles L. Stein

56

Senior Vice President

1997 - Present

Chief Operating Officer

2001 - Present


George M. Bachman

46

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:

 

 

2005

 

2004

 

Stock Prices *

Dividends

 

  Stock Prices *

Dividends

Quarter ended

Low

-

High

Declared*

 

Low

-

High

Declared*

March 31 

$11.47 

-

$13.49 

$0.1000 

 

$10.33 

-

$13.67 

$0.0983 

June 30 

11.45 

-

12.67 

0.1033 

 

11.70 

-

14.93 

0.1000 

September 30 

 12.67 

-

16.84 

0.1033 

 

10.60 

-

12.17 

0.1000 

December 31 

13.46 

-

16.44 

0.1033 

 

11.23 

-

12.83 

0.1000 


* 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 17, 2006, there were approximately 3,700 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, 2005, approximately $7.3 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

101,394*

Equity compensation plans not approved by security holders

0

Total

101,394




* This includes 23,704 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 77,690 shares for the Employee Stock Purchase Plan.



Item 6.

Selected Financial Data


(Dollars in thousands, except per share data)

Years Ended December 31,

 

2005 

 

2004 

 

2003 

  

2002 

  

2001 

 

Revenues

$

130,023 

$

110,039 

$

102,723 

 

$

88,461 

 

$

89,178 

(2)

              

Gross profit

$

47,219 

$

40,689 

$

37,733 

 

$

34,929 

 

$

29,940 

 

Earnings:

             

Continuing operations

$

4,248 

$

3,594 

$

2,522 

 

$

2,761 

(1)

$

2,456 

 

Discontinued operations (4)

 

 

 

9,901 

  

602 

  

596 

 

Net income

$

4,248 

$

3,594 

$

12,423 

 

$

3,363 

(1)

$

3,052 

 
              

Earnings per common share (basic and diluted) (6):

             

Continuing operations

$

0.71 

$

0.60 

$

0.43 

 

$

0.47 

(1)

$

0.43 

 

Discontinued operations (4)

 

 

 

1.69 

  

0.10 

  

0.10 

 

Total

$

0.71 

$

0.60 

$

2.12 

 

$

0.57 

(1)

$

0.53 

 
              

Dividends declared per common share (6)

$

0.41 

$

0.40 

$

0.39 

 

$

0.38 

 

$

0.37 

 
              

Total assets   (3) (7)

$

181,883 

$

169,882 

$

160,944 

 

$

148,487 

 

$

143,236 

(2)

Utility plant – net  (3)

$

123,061 

$

117,191 

$

107,942 

(5)

$

103,357 

(5)

$

92,023 

(2)

Current debt

$

9,558 

$

5,825 

$

2,278 

 

$

19,183 

 

$

20,430 

 

Long-term debt (7)

$

50,620 

$

50,538 

$

50,454 

 

$

50,367 

 

$

50,325 

 

Common shareholders' equity

$

45,503 

$

43,213 

$

41,463 

 

$

30,883 

 

$

29,329 

 


Notes to the Selected Financial Data:


(1) 2002 includes gain after income taxes from the sale of non-utility real property of $70, or $0.01 per share.




(2) The acquisitions in late 2001 added approximately $10,700 to Total assets and $3,975 to Utility plant – net.  Revenue recorded in 2001 from the acquisitions was approximately $326.


(3) The Total assets and Utility plant - net for 2002 and 2001 have been restated to conform to SFAS No. 143, "Accounting for Asset Retirement Obligations".


(4) 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 (for additional information see "Discontinued Operations" in the Notes to Consolidated Financial Statements).  Revenues, Gross profit and Utility plant-net do not include discontinued operations.


(5) The Total assets and Utility plant - net for 2003 and 2002 have been restated to reflect the FPSC approved acquisition adjustment in the amount of approximately $1.0 million.  (For additional information see "Goodwill and Intangible Assets" in the Notes to Consolidated Financial Statements).


(6) 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.




(7) Long-term debt is net of unamortized debt discount. Prior years have been restated to reflect the inclusion of unamortized debt discount.



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. Recent price increases in natural and propane gas, in part as a result of the effects of hurricane Katrina on gas supplies, may have lowered energy use in the later part of 2005 and could affect future demand and net operating income.


For 2005, we have an over-earnings liability for our natural gas segment because our 2005 rate of return exceeds the maximum rate of return allowed by the FPSC. At December 31, 2005, $700,000 was recorded as an over-earnings liability subject to FPSC review. For more information on this liability, see “Outlook, Over-earnings – Natural Gas Segment”, below.


Also in October 2005, the FPSC approved recovery of 2004 natural gas storm costs plus interest over a 30-month period beginning November 2005.  We had deferred our storm costs as a regulatory asset on our balance sheet to be paid by customers.


The FPSC also approved recovery of expenses associated with requesting and evaluating proposals for the 2008 electric fuel contracts and the associated negotiation of these contracts. The FPSC disallowed recovery of expenses relating to a requested surcharge and ordered amortization of these costs over a five-year period beginning, January 1, 2006. The surcharge was requested to help mitigate the future impact of revised fuel contracts.  See “Outlook, Electric Power Supply Contracts” below.


Revenues and Gross Profit

Revenues include normal sales revenues, along with 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 result of operations and fluctuations could distort the relationship of revenues between periods. Because gross profit eliminates these cost recovery revenues, we believe it provides a more meaningful basis for evaluating utility revenues



.


Revenues and Gross Profit

(Dollars in thousands)

 

Year Ended December 31,

 

2005

2004

2003

Natural Gas

 

  

Revenues

$69,094 

$55,962 

$53,610 

Cost of fuel and other pass through costs

42,815 

34,232 

32,463 

Gross Profit

$26,279 

$21,730 

$21,147 

   Units sold:

        One thousand dekatherms (MDth)

6,224 

6,124 

 5,942 

Electric

   

Revenues

$47,450 

$42,910 

$39,519 

Cost of fuel and other pass through costs

33,352 

29,732 

27,987 

Gross Profit

$14,098 

$13,178 

$11,532 

   Units sold:

        Mega watt hours (MWH)

814,353 

766,349 

723,822 

Propane Gas

   

Revenues

$13,479 

$11,167 

$9,594 

Cost of fuel and other pass through costs

6,637 

5,386 

4,540 

Gross Profit

$6,842 

$5,781 

$5,054 

Units sold:

       One thousand dekatherms (MDth)

640 

 614 

575 


Natural Gas

Natural gas revenues increased $13.1 million in 2005 over 2004 primarily due to an $8.6 million increase in 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 recent 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.


Natural gas revenues increased $2.4 million in 2004 over 2003 primarily due to a $1.8 million increase in cost of fuel and other costs that were passed through to customers. Gross profit increased $583,000 or 3%.  The primary reason for the gross profit increase was the interim rate relief beginning in August 2004 and a final increase effective November 2004 as well as normal customer growth and a 3% increase in units sold.  A $1.5 million fee received in 2003 but not in 2004 offset the increase in gross profit.




Electric

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 recently in our Northwest division and increased revenues by approximately $700,000 and gross profit by approximately $91,000 in 2005 over 2004.


Electric revenues increased $3.4 million in 2004 over 2003.  $1.7 million of the increase was for the cost of fuel and other costs that were passed through to customers.  Gross profit increased $1.6 million or 14% in 2004 over 2003.  The increase in gross profit was primarily due to the rate increases granted in March 2004, along with normal customer growth and a 6% increase in units sold.


Propane Gas

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 $380,000 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.


Propane revenues increased $1.6 million and gross profit increased $727,000 or 14% in 2004 compared to 2003.  Additionally, approximately $130,000 of the gross profit increase in 2004 over 2003 is attributable to a refinement of propane inventory estimate that lowered gross profit in the third quarter of 2003.  Propane unit sales increased 7% due primarily to the addition of a large wholesale customer along with an increase in the total number of customers in 2004.


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,

 

2005 

2004

2003

Natural gas

$   20,230 

$   16,752 

$   15,957 

Electric

$   10,596 

$     9,825 

$     9,283 

Propane gas

$     5,756 

$     5,126 

$     4,800 


Natural Gas

Natural gas operating expenses increased $3,478,000, or 21%, in 2005 as compared with 2004. Amortization expense increased $1,099,000. 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 (PE) 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 for amortization expense as an offset to the revenues received, and record a contribution to the related construction expenditures. The FPSC also approved recovery of our expected environmental liability over a 20-year period.


Based on our strategic plan, we have increased efforts in our customer service area to respond to customers. Customer account expense increased $373,000 primarily due to increased payroll expenses for additional staffing and facility and equipment upgrades. There were also increased bad debt expenses 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.


Natural gas operating expenses increased $795,000, or 5%, in 2004 as compared with 2003.  Depreciation and amortization expense increased $353,000 due to an increase in plant assets and customer account expense increased $260,000.  The increase in customer account expense in 2004 over 2003 was primarily due to a reduction, in the first quarter of 2003, of operating expenses because of a $172,000 recovery of bad debt related to the contract with Lake Worth Generation.  Other operating expense increased $61,000, partially due to an increase in underground natural gas line location expense of $32,000 that was caused by an increase in the quantity of natural gas line locations performed due to construction related projects.  The increase was offset by a decrease of $121,000 in maintenance expenses in the first quarter of 2004 related to an abandoned construction project for a main insertion failure at Royal Park Bridge in South Florida.


Electric

Electric operating expenses increased $771,000, or 8%, in 2005 as compared with 2004.  As we continue 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.


Electric operating expenses increased $542,000, or 6%, in 2004 as compared with 2003.  Maintenance increased $205,000 primarily due to increased maintenance requiring subcontractor involvement in maintenance projects (more costly than in house labor) and $68,000 increase in tree trimming expense due to additional tree trimming activities that were needed to properly maintain line clearances and reduce potential outages.  Customer account expense increased $34,000.


Propane Gas

Propane gas operating expenses increased $630,000, or 12%, in 2005 as compared with 2004. As we continued to focus on increasing our propane 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, 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 segment.


Propane gas operating expenses increased $326,000, or 7%, in 2004 as compared with 2003.  Other operating expenses increased $50,000.  Depreciation expense also increased $52,000 due to increases in plant assets.  Uncollectible accounts increased $35,000 due to increased accounts receivable.


Administrative Expenses

Administrative expenses increased $996,000, or 13%, in 2005 over 2004. These expenses are related to all of our operating segments. 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. In an effort to manage future expected increases in the pension liabilities, we decided to discontinue eligibility to our defined benefit pension plan for new employees. We replaced the defined benefit pension plan with a 401K-match plan for new employees. 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 impacts from our focus on hurricane preparations and the recent hurricanes, our safety expense increased by $235,000. A portion of this increase related to an additional safety employee and a new safety incentive program.


Administrative expenses shared by all of our operating segments increased $532,000, or 8%, in 2004 over 2003.  Pension expense increased $431,000 due to the performance of the investments in the pension plan.  Insurance increased $201,000 primarily due to increased medical costs.  Amortization of electric rate case expense began in April 2004 and increased expense by $59,000.  We had accumulated charges earlier in 2004 relating to a potential equity offering.  Due to market conditions and our ability to increase the line of credit to address cash needs, we cancelled the potential equity offering in July 2004.  Accumulated charges of approximately $50,000 were expensed in July 2004.  This was more than offset by a decrease in outside services primarily due to a change in external auditors.


Total Other Income and Deductions

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


Merchandise and Services Revenues and Expenses

Merchandise and services revenues and expenses both increased in 2005 from 2004 but merchandise 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 tanks to supply back-up generators. We had increased expenses from sub-contractors that were not passed on to customers in sales prices. Management is currently reviewing the profitability of the various merchandise installation costs and considering increasing installation fees to improve profitability in this area.




Merchandise and service revenue and expenses both increased in 2004 from 2003; however merchandise profitability decreased $69,000 primarily due to increased expenses from sub-contractors on increased installations and service.


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. We also made an interest payment of $18,000 as the result of the IRS audit of prior years’ tax returns. 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.


In 2004, total interest expense decreased $26,000 from 2003 primarily due to a decrease in interest expense on short-term debt resulting from a decrease in the average outstanding loan balance on the line of credit.


Other

Non-operating income increased by $200,000 in 2004 from 2003 largely due to $251,000 additional interest income associated with the sale of the water assets.  This was offset by a $149,000 adjustment in 2003 required by the FPSC to move environmental interest income to the environmental liability reserve.


Income Taxes

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 water 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.


Discontinued Operations

See Note 3, “Discontinued Operations” for additional information regarding the sale of water in 2003 and the effects on the financial statements.


Liquidity and Capital Resources


 

Summary of Primary Sources and Uses of Cash  

(Dollars in thousands)

 

Year Ended December 31,

 

2005 

2004

2003

Sources of Cash:

   

Operating activities, including working capital changes

$10,213 

$11,673 

 $6,983 

Proceeds from issuance of short-term debt

3,733 

 3,547 

Proceeds from sale of water plant

  

19,372 

Other sources of cash

1,214 

 648 

 640 

Uses of Cash:

   

Construction expenditures

12,441 

 13,731 

 9,693 

Repayment of short-term debt

  

16,907 

Dividends paid

2,448 

2,368 

 2,289 

Other uses of cash

75 

129 

447 

     Net source (use) of cash

 $    196 

$   (360)

$(2,341)






Cash Flows

Operating Activities

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 are 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 both 2003 and 2004 as a result of bonus depreciation, resulting in lower taxes in those years.  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 $4.0 million.  Accounts payable increased $3.3 million primarily due to the increased cost of fuel in our natural gas segment.


Net cash flow provided by continuing operating activities increased in 2004 by approximately $4.7 million from 2003.  The increase was primarily due to the receipt of a $3.9 million estimated tax payment refund received in 2004. This refund was primarily due to the deferral of the gain for tax purposes on the sale of the water division in 2003.  A $2.9 million estimated tax payment 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 (see Note 3, “Discontinued Operations”).  We applied for a refund and received $3.9 million in July 2004, which included other estimated tax overpayments.


Investing Activities

Construction 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 approximately $600,000, 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, an additional propane community gas system for approximately $300,000 and other various capital expenditures.


Construction expenditures increased $4.0 million through December 2004 compared to December 2003.  Construction in 2004 increased approximately $2.7 million from rebuilding two substations in the electric segment.  In addition, approximately $575,000 was spent on additional propane community gas systems.


Financing Activities

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


Proceeds from the sale of the water assets of $19.2 million added to cash in 2003. These proceeds were primarily used to pay off short-term debt in 2003.




Capital Resources

We currently have a $12 million line of credit (LOC), which expires on June 30, 2007. Upon 30 days notice by us we can increase the LOC to a maximum of $20 million.  The LOC 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 exceeded and management believes we are in full compliance with all covenants and anticipates continued compliance.  We reserve $1 million of the LOC to cover expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane facilities. As of December 31, 2005, the amount borrowed from the LOC was $9.6 million. The LOC, long-term debt and preferred stock as of December 31, 2005 comprised 57% 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 LOC, 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, 2005, such calculation would permit the issuance of approximately $36.2 million of additional bonds.


On October 19, 2005 we received approval from the FPSC to issue and sell/or exchange an additional amount of $45.0 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 2006.


We have $3.3 million in invested funds held 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 LOC.


Construction expenditures are expected to be higher in 2006 compared to 2005 by approximately $6.7 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 another location to allow for clean up of the property. It will not be possible to rebuild at the current location since the property has been rezoned with a residential designation. The estimated cost of land is $8 million to $10 million.  We are planning to build and complete this new facility in the next five years.  The other expected construction expenditures in 2006 are expected to be slightly higher than construction expenditures in 2005 .  We do not currently have any material commitments for construction expenditures in 2006 other than vehicles of approximately $240,000.


We are currently testing a transformer in our Northeast division, and based on the results of the tests, we may be required to either repair or replace this transformer. The estimated cost of repair is approximately $50,000 to $80,000. If replacement is required, the cost is expected to be approximately $500,000.   Based upon the results, repairs or replacement would be expected to occur in the second half of 2006.


In addition, cash requirements might 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 $2 million in 2007, with remaining payments which could total approximately $10.5 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. Current projections indicate that we will need to make annual contributions in our defined benefit pension plan of $250,000 in 2006 and $290,000 in 2007. These estimates are based on funding laws as of January 1, 2006. Contribution amounts in 2007 and beyond will likely be affected by pending funding reform that Congress is currently considering which would increase those funding requirements.


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 2006 of $12 million to $15 million 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 as early as 2007. We may consider equity or debt offerings for any such additional financing. There can be no assurance, however, that equity or debt financing will be available on favorable terms, or at all, in 2006 or later years when the company is seeking such financings.




Outlook


Pension and Insurance Expenses

Pension and Insurance costs have been and are expected to continue to increase.  Pension expenses increased in 2005 by $274,000 and current actuarial estimates show pension expense will increase an additional $203,000 in 2006.  Pension expenses are projected to continue increasing in 2007.  Insurance expenses including Medical, Liability and Workers’ Compensation, increased by $130,000 in 2005 and are expected to increase further in 2006.


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


Due to significant cost increases for our defined benefit pension plan over the past three years and with expectations that these cost increases will continue in the years ahead, we discontinued eligibility to our pension plan for all new non-union hires effective January 1,



2005 and are phasing out the plan for new union members. Five of our six union contracts have accepted this change for their new union members, and we intend to negotiate this issue in the remaining union contract in June of 2006.


For those new hires no longer eligible for the defined benefit pension plan, we have established a 401K plan with match contributions. The 401K provides a company match of 50 cents for every dollar contributed by an employee on the first 6% of their salary, for a total annual company contribution of up to 3%.  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 expire December 31, 2007.  The contracts currently provide electricity to our customers at rates that are much lower than market rates. The savings are passed through to our customers without profit to the Company. Obtaining supply contracts at below market prices will not reoccur.  We expect a substantial increase between our current contract prices and the anticipated contract prices. We have entered into negotiations with suppliers to be our ongoing electricity suppliers. During 2006, we anticipate completion of final contracts for the supply of our electricity beginning January 1, 2008.  We are unable to estimate what impact, if any, higher rates could have on electric consumption.


In December 2005 the FPSC approved recovery of expenses associated with requesting and evaluating proposals for the 2008 fuel contracts and the associated negotiation of the contracts.  As of December 31, 2005, $237,000 was included in the 2006 fuel charges that will be passed through to electric customers.


The company requested a fuel surcharge to help mitigate the future price increases expected in 2008. The FPSC disallowed the fuel surcharge and disallowed the related administrative expenses associated with this request for recovery through the fuel clause.  As of December 31, 2005, $24,000 was deferred and, with FPSC approval, will be amortized to operating expenses over five years beginning January 1, 2006.


Propane

We currently have propane advance purchase agreements at close to current market price. The purchase of propane gas under these agreements in the first quarter of 2006 is not expected to provide an increase to the gross profit in our propane segment.  The realization of any additional gross profit depends on market conditions affecting the cost of propane over the first quarter of 2006.


These advance purchase agreements are made in the normal course of procuring propane supplies. Similar agreements provided additional gross profit of approximately $383,000 in 2005 and $242,000 in 2004.


Management is currently performing a comprehensive review of the propane segment for additional ways to reduce expenses and increase revenues.  These revenues or savings, if any, would be realized during 2006.


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 have



estimated that we will have over-earnings in 2005 of $700,000. This liability has 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. We believe our 2005 estimate of our over-earnings liabilities is accurate, but it could change upon the FPSC finalization and review of our earnings.


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. Recently, the FPSC ordered 2002 natural gas over-earnings of approximately $118,000 to be added to our “regulatory liability – storm reserve” to cover future storm costs. Finalization of the disposition and determination of the amount of 2005 natural gas over-earnings is expected in 2006.


The amount of natural gas over-earnings for 2005 was primarily a result of delayed and cancelled capital projects, reduced area expansion amortization and slightly higher sales units and customers than projected. The delayed and cancelled capital projects contributed significantly to the lower than expected increase in depreciation expenses in our natural gas segment.  Operating expenses, with the exception of the depreciation and amortization, were close to expectations. Since this was the first year of our full rate relief in our natural gas operations and the rate relief covered expected levels of expenses and units sold, these items impacted the amount of over-earnings liability and did not affect net operating results.


Electric Customers

A large commercial customer in our electric division will be closing its operations by 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.


In 2004, a large distribution center was built in our Northwest division and a distribution park is under construction in this same area. A third distribution facility is near completion. 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 this additional development.


Indiantown Gas Agreement

We have signed a letter of intent and are in negotiations for a natural gas territorial agreement with Indiantown Gas for a location adjacent to and within its service area. The FPSC is aware of and supports this agreement.  Significant residential development is planned for Indiantown in Martin County. We plan to transport natural gas through Indiantown’s system to new developments. In the early phase, Indiantown Gas will provide operational and customer service related work. Development is expected to begin in 2006.  We do not anticipate any significant increase in the number of customers or revenues during 2006, but both should increase as the development continues. Early estimates for this area indicate the number of customers may increase by 7,500 over the next ten years.


Lake Worth Utilities

The City of Lake Worth formed a task force to review their electric utility in December 2005.  One option that the task force is reviewing is the possible sale of the City of Lake Worth’s electric generation plant. If sold, and if the Gas Transportation agreement



between our company and the City of Lake Worth is terminated, the City will be obligated to pay our company the amount of our undepreciated investment in our gas facilities serving the City of Lake Worth plus any costs incurred by our company to abandon the gas facilities. If this agreement is terminated in 2006, the City of Lake Worth will have to pay us approximately $4 million plus the costs of abandonment.  In addition, it is possible that the natural gas transportation sales through this pipeline to the electric generation facility could cease. Our revenues and gross profit from the City of Lake Worth would decrease annually by approximately $760,000.


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 

$        - 

$ 1,409 

 $ 2,818 

$ 48,273 

Long-term Debt Interest

67,852 

 3,949 

 7,829 

7,349 

48,725 

Operating Lease Obligations

260 

103 

100 

55

2

Natural Gas and Propane Purchase Obligations

65,700 

36,885 

10,153 

8,313 

10,349 

Electric Purchase Obligations

292 

56 

101 

90 

45 

Other Purchase Obligations

2,464 

1,204 

1,206 

18

36

Total

$189,068 

$ 42,197 

$ 20,798 

 $ 18,643 

 $ 107,430 


Long-term Debt

The Long-term debt obligations are principal amounts.


Operating Leases

Our total operating lease obligation is $260,000. 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 $134,000 over the next five years. We are in the process of renegotiating the terms of this lease and may be able to terminate this lease at an earlier date. 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 value of purchase orders considered an obligation.


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 2006.  Actuarial forecasts estimate a contribution may be required of $250,000 in 2006 and $290,000 in 2007. Contribution amounts beyond 2007 may be affected by pending funding reform Congress is considering. Environmental clean up is anticipated to require approximately $2.0 million in 2007, the remainder to be paid in the following years.


We have medical postretirement payments relating to retiree medical insurance. These payments are not included in the above table. Estimated future payments are contained in Note 13 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 No. 154

In May 2005, the Financial Accounting Standards Board (FASB) issued Statement No. 154, “Accounting Changes and Error Corrections”.  This Statement applies to all voluntary changes in accounting principle and requires retrospective application to prior period financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effects of the change.  This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We expect to adopt SFAS No. 154 effective January 1, 2006. We do not believe adoption of this statement will have a material impact on our financial condition or results of operation.


Financial Accounting Standard Board Interpretation No. 47

In March 2005, the FASB issued Interpretation No. 47, “An Interpretation of FASB Statement No. 143”.  FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, requires that the fair value of an asset retirement obligation be recognized at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset.  SFAS No. 143 also requires that components of previously recorded depreciation related to the cost of removal of assets upon retirement, whether legal asset retirement obligations or not, be removed from a company’s accumulated depreciation reserve. We adopted the provisions of the Statement as of January 1, 2003, as prescribed by the FPSC.  Under FPSC guidelines, the estimated cost of removal expenses for normal retirements related to regulated fixed assets were reserved through the depreciation expense and accumulated reserves. This was disclosed in a footnote until December 31, 2003, when the estimated cost of removal from accumulated depreciation was reclassified to a regulatory liability for the obligation.


This Interpretation addresses the legal obligation to retire an asset when the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the Company.  This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005 for calendar-year entities).  We have determined that the adoption of this interpretation will not have a material impact on our financial condition or results of operation.  We expect to adopt Interpretation No. 47 effective January 1, 2006.


Financial Accounting Standard No. 123R

In December 2004, the FASB issued SFAS No. 123R (revised 2004), “Share-Based Payment”.  This revised statement is effective for the first interim or annual reporting period that begins after June 15, 2005. This Statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services.  However, during the first quarter of 2005, the Securities and Exchange Commission approved a new rule, Staff Accounting Bulletin 107, that delays the adoption of this standard to the beginning of the next fiscal year, instead of the next reporting period that begins after June 15, 2005.  The rule does not change the accounting required by Statement No. 123(R).




In October 2005, FASB issued Staff Position (FSP) No. 123 (R)-2 that provides guidance on the application of grant date as defined in FASB Statement No. 123 (revised 2004), Share-Based Payment.


We began recording compensation expense relating to our employee stock purchase plan in compliance with SFAS 123 in the first quarter of 2004. We do not feel that the adoption of these revisions will result in any material change to our financial statements and current method of reporting stock based transactions. The 2005 expense was $61,000.


Critical Accounting Policies and Estimates


Regulatory Accounting

We prepare our financial statements in accordance with the provisions of Statement of Accounting Standards No. 71(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. We use estimates including the accrual for pensions, environmental liabilities, over-earnings liability, unbilled revenues, uninsured liability claims, and the regulatory deferred income tax liability.


·

Pension- An actuary calculates the estimated pension liability in accordance with FASB 87.

·

Environmental liabilities-These liabilities are subject to certain unknown future events.

·

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.

·

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.  Until January 1, 2004, we were self-insured for medical claims and required accruals of estimated claims.

·

Regulatory deferred income tax liability-This liability is estimated based on historical data and is 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, is 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; see Note 11- "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”.  In simple terms, these are obligations of a company that are not disclosed on the balance sheet. For the full definition of this term, see Item 303(a)(4) of Regulation S-K.


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 2006 of $12 million to $15 million 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.

·

Pension expenses will continue to increase in 2006.

·

Other insurance costs will increase in 2006.

·

Our 2005 over-earnings liability in natural gas will materialize as estimated after the FPSC review and audit.

·

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

·

The development in Indiantown will occur as estimated and we will provide natural gas to this area.

·

The purchase of land for our new natural gas and propane division office will occur in 2006.

·

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

·

The loss of the large commercial customer in our Northwest division will occur in 2006.

·

Lake Worth Utilities could be sold and our agreement with them for facilities may be terminated. A payment for this termination including abandonment costs would occur and lost revenues could materialize from the loss of service to this customer.




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 jurisdictions, we are 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".


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 $9.6 million at the end of December 2005.  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 long-term receivable (non-interest bearing) 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 $6.0 million to $5.9 million.


In 2005, 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 $63.0 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 $9.6 million on December 31, 2005 and $5.8 million on December 31, 2004.  A hypothetical 1% increase in interest rates would have resulted in a decrease in annual earnings for 2005 by $96,000 and for 2004 by $36,000, 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

 

2005

 

2004

 

2003

Natural gas

69,094 

55,962 

53,610 

Electric

 

47,450 

 

42,910 

 

39,519 

Propane gas

 

13,479 

 

11,167 

 

9,594 

Total revenues

 

130,023 

 

110,039 

 

102,723 

Cost of Fuel and Other Pass Through Costs

 

82,804 

 

69,350 

 

64,990 

Gross Profit

 

47,219 

 

40,689 

 

37,733 

Operating Expenses

      

Operation

 

22,881 

 

20,068 

 

19,015 

Maintenance

 

3,566 

 

2,982 

 

2,881 

Depreciation and amortization

 

7,266 

 

5,900 

 

5,492 

Taxes other than income taxes

 

2,869 

 

2,753 

 

2,652 

Total operating expenses

 

36,582 

 

31,703 

 

30,040 

Operating Income

 

10,637 

 

8,986 

 

7,693 

Other Income and (Deductions)

      

Merchandise and service revenue

 

4,590 

 

3,366 

 

2,799 

Merchandise and service expenses

 

(4,664)

 

(3,326)

 

(2,690)

Other income

 

569 

 

625 

 

394 

Other deductions

 

(29)

 

20 

 

(19)

Interest expense on long-term debt

 

(3,949)

 

(3,949)

 

(3,949)

Interest expense on short-term borrowings

 

(79)

 

(42)

 

(75)

Customer deposits and other interest expense

 

(540)

 

(471)

 

(464)

Total other deductions – net

 

(4,102)

 

(3,777)

 

(4,004)

Earnings Before Income Taxes and Discontinued Operations

 

6,535 

 

5,209 

 

3,689 

Income Taxes

 

(2,287)

 

(1,615)

 

(1,167)

Earnings from Continuing Operations

 

4,248 

 

3,594 

 

2,522 

Discontinued Operations

      

Income from discontinued operations-water division

 

 

 

149 

Income taxes

 

 

 

(16)

Gain on disposal of water division, net of income taxes of $5,955

 

 

 

9,768 

Total income from discontinued operations

 

 

 

9,901 

Net Income

 

4,248 

 

3,594 

 

12,423 

Preferred Stock Dividends

 

29 

 

29 

 

29 

Earnings for Common Stock

$

4,219 

3,565 

12,394 

Earnings Per Common Share (basic and diluted):

 

Continuing Operations

$

.71 

.60 

.43 

Discontinued Operations

 

 

 

1.69 

Total

$

.71 

.60 

2.12 

Dividends Declared Per Common Share

$

.41 

.40 

.39 

Average Shares Outstanding

 

5,952,684 

 

5,908,220 

 

5,858,549 


See Notes to Consolidated Financial Statements








CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

  

December 31,

ASSETS

 

2005

 

2004

Utility Plant

    

Natural gas

$

89,835 

83,549 

Electric

 

70,084 

 

67,888 

Propane gas

 

15,500 

 

13,466 

Common

 

3,859 

 

5,694 

Total

 

179,278 

 

170,597 

Less accumulated depreciation

 

56,217 

 

53,406 

Net utility plant

 

123,061 

 

117,191 

     

Current Assets

    

Cash

 

695 

 

499 

Accounts receivable

 

14,997 

 

11,003 

Notes receivable

 

299 

 

394 

Allowance for uncollectible accounts

 

(272)

 

(269)

Unbilled receivables

 

1,918 

 

2,285 

Inventories (at average or unit cost)

 

3,781 

 

2,956 

Prepaid expenses

 

951 

 

814 

Income tax prepayments

 

1,159 

 

1,625 

Under-recovery of fuel costs

 

3,375 

 

274 

Total current assets

 

26,903 

 

19,581 

     

Other Assets

    

Investments held for environmental costs

 

3,258 

 

3,183 

Other regulatory assets – storm reserve

 

452 

 

416 

Other regulatory assets – environmental

 

8,868 

 

9,297 

Long-term receivables and other investments

 

5,794 

 

5,811 

Deferred charges

 

6,751 

 

7,652 

Goodwill

 

2,405 

 

2,405 

Intangible assets (net)

 

4,391 

 

4,346 

Total other assets

 

31,919 

 

33,110 

Total

$

181,883 

169,882 

  

  See Notes to Consolidated Financial Statements




CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)    

  

December 31,

CAPITALIZATION AND LIABILITIES

 

2005

 

2004

Capitalization

    

Common shareholders' equity

$

45,503 

43,213 

Preferred stock

 

600 

 

600 

Long-term debt

 

50,620 

 

50,538 

Total capitalization

 

96,723 

 

94,351 

     

Current Liabilities

    

Line of credit

 

9,558 

 

5,825 

Accounts payable

 

13,166 

 

9,861 

Insurance accrued

 

296 

 

364 

Interest accrued

 

1,014 

 

969 

Other accruals and payables

 

1,984 

 

 2,020 

Taxes accrued

 

1,512 

 

2,081 

Deferred income tax

 

1,066 

 

241 

Over-earnings liability

 

700 

 

Over-recovery of conservation

 

24 

 

94 

Customer deposits

 

8,068 

 

7,047 

Total current liabilities

 

37,388 

 

28,502 

     

Other Liabilities

    

Deferred income taxes

 

17,568 

 

18,424 

Unamortized investment tax credits

 

411 

 

491 

Environmental liability

 

14,001 

 

13,989 

Regulatory liability - cost of removal

 

8,256 

 

7,824 

Regulatory tax liabilities

 

991 

 

1,113 

Long-term medical and pension reserve

 

2,663 

 

1,757 

Customer advances for construction

 

2,346 

 

1,893 

Regulatory liability - storm reserve

 

1,536 

 

1,538 

Total other liabilities

 

47,772 

 

47,029 

Total

$

181,883 

169,882 


See Notes to Consolidated Financial Statements

    





CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in thousands)

  

December 31,

  

2005

 

2004

Common Shareholders' Equity

    

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,152,676 shares in 2005; 6,130,097 shares in 2004

$

9,229 

9,195 

Paid-in capital

 

5,998 

 

5,806 

Retained earnings

 

33,625 

 

31,849 

Treasury stock - at cost (188,994 shares in 2005, 205,241 shares in 2004)

 

(3,349)

 

(3,637)

Total common shareholders' equity

 

45,503 

 

43,213 

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

 

(1,880)

 

(1,962)

Total long-term debt

 

50,620 

 

50,538 

Total Capitalization

$

96,723 

94,351 

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

 

Treasury Shares

 

Treasury Shares Cost

Balances as of December 31, 2002

6,066,238 

9,099 

5,579 

20,529 

 

244,028 

(4,324)


Net income

 

 

 

12,423 

 

 

Dividends

 

 

 

(2,314)

 

 

Stock plans

31,240 

 

47 

 

53 

   

(20,966)

 

371 

Balances as of December 31, 2003

6,097,478 

 

9,146 

 

       5,632 

 

30,638 

 

223,062 

 

(3,953)


Net income

 

 

 

3,594 

 

 

Dividends

 

 

 

(2,383)

 

 

Stock plans

32,619 

 

49 

 

 174 

   

(17,821)

 

316 

Balances as of December 31, 2004

6,130,097 

 

9,195 

 

5,806 

 

31,849 

 

205,241 

 

(3,637)


Net income

 

 

 

4,248 

 

 

Dividends

 

 

 

(2,472)

 

 

Stock plans

22,579 

 

34 

 

192 

   

(16,247)

 

288 

Balances as of December 31, 2005

6,152,676 

9,229 

5,998 

33,625 

 

 188,994 

(3,349)

            


See Notes to Consolidated Financial Statements



CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

  

Years Ended December 31,

  

2005

 

2004

 

2003

Cash Flows from Operating Activities:

      

Net income

$

4,248 

3,594 

12,423 

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

      

Income from discontinued operations, net of tax

 

 

 

(9,901)

Depreciation and amortization

 

7,266 

 

5,900 

 

5,492 

Deferred income taxes

 

(153)

 

2,470 

 

8,408 

Bad debt expense

 

359 

 

409 

 

174 

Investment tax credits

 

(81)

 

(83)

 

(97)

Other

 

751 

 

121 

 

418 

Interest income from sale of non-utility property

 

(192)

 

(271)

 

(190)

Compensation expense from the issuance of stock

 

58 

 

91 

 

Effects of changes in:

      

Receivables

 

(4,351)

 

(1,688)

 

(1,091)

Unbilled receivables

 

367 

 

(612)

 

(203)

Inventories and prepayments

 

(495)

 

2,746 

 

(4,633)

Accounts payable and accruals

 

 5,398 

 

1,131 

 

(3,458)

Over (under) recovery of fuel costs

 

(3,171)

 

(1,991)

 

40 

Area expansion program deferred costs

 

109 

 

 (372)

 

(431)

Environmental liability

 

 429 

 

(586)

 

(451)

Other

 

 (329)

 

 814 

 

 483 

     Net cash provided by operating activities

 

10,213 

 

11,673 

 

6,983 

Cash Flows from Investing Activities:

      

Construction expenditures

 

(12,441)

 

(13,731)

 

(9,693)

Purchase of Nature Coast Company, net of cash acquired

 

 

 

(15)

Customer advances received for construction

 

454 

 

144 

 

168 

Purchase of long-term investments

 

(75)

 

(34)

 

(334)

Proceeds received on notes receivable

 

304 

 

57 

 

Issuance of notes receivable

 

 

(95)

 

Proceeds provided by sale of water plant

 

 

 

19,372 

     Net cash provided by (used in) investing activities

 

(11,758)

 

(13,659)

 

9,498 

Cash Flows from Financing Activities:

      

Net change in short-term borrowings

 

3,733 

 

3,547 

 

(16,907)

Proceeds from common stock plans

 

456 

 

447 

 

472 

Dividends paid

 

(2,448)

 

(2,368)

 

(2,289)

     Net cash provided by (used in) financing activities

 

1,741 

 

1,626 

 

(18,724)

Net Cash Used in Discontinued Operations

 

 

 

(98)

Net Increase (Decrease) in Cash

 

196 

 

(360)

 

(2,341)

Cash at Beginning of Year

 

499 

 

859 

 

3,200 

Cash at End of Year

$

 695 

 499 

859 

Supplemental Cash Flow Information

      

Cash was paid during the years as follows:

      

     Interest

$

4,469 

4,357 

4,358 

     Income taxes

$

2,698 

1,215 

4,188 

     Non-cash activities:

   

     

          Note receivable from sale of water plant

$

              - 

           - 

5,716 


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 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 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 2005 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.  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)

 

2005

2004

Assets

  

Deferred development costs  (1)

$4,190 

$4,299 

Environmental assets (2)

8,868 

9,297 

Storm Reserve assets (3)

452 

416 

Unamortized Rate Case expense

541 

704 

Under recovery of fuel costs

3,375 

274 

Unamortized piping and conversion costs   (1)

1,587 

1,449 

Unamortized loss on reacquired debt   (1)

227 

245 

Total Regulatory Assets

$19,240 

$16,684 

  

  

Liabilities

  

Tax liabilities

$991 

$1,113 

Cost of removal

8,256 

7,824 

Storm reserve liabilities

1,536 

1,538 

Over recovery of conservation

24 

94 

Over-earnings liability (4)

700 

Total Regulatory Liabilities

$11,507 

$10,569 


(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 reclassified the amount due from customers as a regulatory asset for environmental costs.  This was authorized by the FPSC in their most recent natural gas rate proceeding and will be recovered over 20 years.

(3)

The Company has been authorized by the FPSC recovery of Storm damages incurred in 2004 in their natural gas operations and will recover those costs from customers over 30 months beginning November 2005.

(4)

The Company has estimated over-earnings in 2005 for regulated natural gas operations of $700,000 and recorded this liability and reduction to 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.


The base revenues 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.  For the Company to recover the effects of inflation and construction expenditures for regulated segments, a request for an increase in base revenues would be required with the filing of two separate rate cases, electric and natural gas.  In 2003 the Company successfully filed for electric rate increases and petitioned to consolidate the two electric "entities" into one entity.  In 2004 the Company successfully filed for a natural gas rate increase.




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 possible 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 include base revenues, fuel adjustment charges, conservation charges and the pass-through of certain governmental imposed taxes based on revenues.  Specific revenues are collected from separate FPSC approved rates that allow direct recovery of expenses from the Company’s customers for fuel, conservation, and revenue based taxes. Any over or under recovery of these expense items are deferred and subsequently refunded or collected in the following period.


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.


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, is 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.


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

 

Balance at Beginning of Year

Write-offs

Provisions to Bad Debt Expense

Balance at End of Year

2003

$ 304,000 

301,000 

177,000 

$ 180,000 

2004

$ 180,000 

 320,000 

409,000 

$ 269,000 

2005

$ 269,000 

 292,000 

295,000 

$ 272,000 


I.  Utility Plant and Depreciation

Utility plant is stated at original cost.  Propane utility plant that has been acquired in acquisitions is stated at fair market value at the time of each acquisition.  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.  See Note 2 for additional information relating to the acquisition adjustment.


Utility Plant

(Dollars in thousands)

Plant Classification

 2005

2004

Land

$      1,124 

$      1,133 

Buildings

6,862 

6,667 

Distribution

147,580 

138,159 

Transmission

6,799 

6,390 

Equipment

11,534 

10,071 

Furniture and Fixtures

369 

403 

Work-in-Progress

5,010 

7,774 

 

$ 179,278 

$ 170,597 


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 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 2005, 3.6% in 2004, and 3.4% in 2003


J. Impact of Recent Accounting Standards


Financial Accounting Standard No. 154

In May 2005, the Financial Accounting Standards Board (FASB) issued Statement No. 154, “Accounting Changes and Error Corrections”.  This Statement applies to all voluntary changes in accounting principle and requires retrospective application to prior period financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effects of the change.  This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company expects to adopt SFAS No. 154 effective January 1, 2006. 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 Board Interpretation No. 47

In March 2005, the FASB issued Interpretation No. 47, “An Interpretation of FASB Statement No. 143”.  FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, requires that the fair value of an asset retirement obligation be recognized at the time those obligations are incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset.  SFAS No. 143 also requires that components of previously recorded depreciation related to the cost of removal of assets upon retirement, whether legal asset retirement



obligations or not, be removed from a company’s accumulated depreciation reserve. The Company adopted the provisions of the Statement as of January 1, 2003, as prescribed by the FPSC.  Under FPSC guidelines, the estimated cost of removal expenses for normal retirements related to regulated fixed assets were reserved through the depreciation expense and accumulated reserves. This was disclosed in a footnote until December 31, 2003, when the estimated cost of removal from accumulated depreciation was reclassified to a regulatory liability for the obligation.


This Interpretation addresses the legal obligation to retire an asset when the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the Company.  This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005 for calendar-year entities).  The Company has determined that the adoption of this interpretation will not have a material impact on its financial condition or results of operation.  The Company expects to adopt Interpretation No. 47 effective January 1, 2006.


Financial Accounting Standard No. 123R

In December 2004, the FASB issued SFAS No. 123R (revised 2004), “Share-Based Payment”.  This revised statement is effective for the first interim or annual reporting period that begins after June 15, 2005. This Statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services.  However, during the first quarter of 2005, the Securities and Exchange Commission approved a new rule, Staff Accounting Bulletin 107, that delays the adoption of this standard to the beginning of the next fiscal year, instead of the next reporting period that begins after June 15, 2005.  The rule does not change the accounting required by Statement No. 123(R).


In October 2005, FASB issued Staff Position (FSP) No. 123 (R)-2 that provides guidance on the application of grant date as defined in FASB Statement No. 123 (revised 2004), Share-Based Payment.


The Company began recording compensation expense relating to the employee stock purchase plan in compliance with SFAS 123 in the first quarter of 2004. The Company does not feel that the adoption of these revisions will result in any material change to its financial statements and current method of reporting stock based transactions. The 2005 expense was $61,000.


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 2004 and 2005 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 $500,000 in the natural gas segment and $1.9 million in the propane gas segment.




The Company requested approval from the FPSC to include the goodwill and intangible assets associated with the acquisition of Atlantic Utilities in the rate base (regulated investment). In October 2004 the portion included in goodwill that represented the difference between fair market value of the assets acquired and the original cost was approved for recovery as an acquisition adjustment.  This acquisition adjustment amounted to approximately $1.0 million and was reclassified from goodwill to an acquisition adjustment included in Property, Plant and Equipment in the fourth quarter of 2004.


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)

  

2005 

2004 

Customer distribution rights

(Indefinite life)

$ 1,900 

$ 1,900 

Customer relationships

(Indefinite life)

900 

900 

Software

(Five to nine year life)

2,971 

2,751 

Non-compete agreement

(Five year life)

35 

35 

Accumulated amortization

(1,415)

(1,240)

Total intangible assets, net of amortization

$ 4,391 

$ 4,346 


The 2005 amortization expense of computer software is approximately $245,000. 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.


3.

Discontinued Operations


Water Service

In 2003, the Company sold the assets of its water utility system.  The fair value of the consideration was approximately $25.0 million.  The City of Fernandina Beach (City) paid $19.2 million in cash at closing and agreed to pay future consideration of approximately $7.4 million in variable annual installments until February 15, 2010. The present value of the remaining balance of the long-term water receivable is $6.0 million using a discount rate of 4.34% at December 31, 2005. The current portion of the long-term receivable is classified in notes receivable, and the remaining is classified in long-term receivables and other investments on our balance sheet. The gain on the disposal of discontinued operations, including the income from discontinued operations for 2003 was $15.9 million or $9.9 million after income tax.


Estimated Annual Future Value of Consideration Due from the City

As of December 31, 2005

(Dollars in thousands)

 

Estimated Timing of Payments

 

Present Value of Water Receivable

2006

$

300 

$

299 

2007

 

300 

 

286 

2008

 

300 

 

274 

2009

 

300 

 

263 

2010

 

5,855 

 

4,913 

Total

$

7,055 

$

6,035 


Results of Discontinued Operations

Year ended December 31, 2003

Results of Water Division

  

(Dollars in thousands)

 

2003

Revenues

$

679 

Gross profit

 

651 

Income from discontinued operations before income taxes

 

149 

Income taxes

 

(16)

Income from discontinued operations before gain

$

133 


4. 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 has estimated over-earnings in 2005 for regulated natural gas operations of $700,000. This liability has been included in 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 2005 estimate of the over-earnings liabilities is accurate, but it could change upon the FPSC finalization and review of earnings.


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.  Recently, the FPSC ordered 2002 natural gas over-earnings of approximately $118,000 to be added to the Company’s “regulatory liability – storm reserve” to cover future storm costs. Finalization of the disposition and determination of the amount of 2005 natural gas over-earnings is expected in 2006.


5. Storm Reserves

As of December 31, 2005, the electric storm reserve was approximately $1.5 million. Since the last order on the 1999 electric disposition of over-earnings, the FPSC has allowed the Company the automatic flexibility of 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 the electric divisions. In 2005, 2004 and 2003 there were no electric over-earnings and accordingly no additional amounts were applied to the storm damage reserves.


In October 2005, the FPSC approved recovery of 2004 natural gas 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, 2005, the amount of natural gas regulatory asset relating to storm was $452,000.




In 2005, the FPSC approved applying 2002 natural gas over-earnings of $118,000 to the storm reserve to cover future storm costs.  This is included as part of the “regulatory liability – storm reserve” on the balance sheet.


6. 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 intends to purchase property that is similar or related in service or use within the replacement periods with the exception of the intangible assets.  During the Company’s recent IRS audit, 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 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 (see Note 3 – “Discontinued Operations”).  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,

  

2005

 

2004

 

2003

Current payable

      

  Federal

$

2,150 

(566)

(1,007)

  State

 

370 

 

(96)

 

(174)

  

2,520 

 

(662)

 

(1,181)

Deferred

      

  Federal

 

(143)

 

2,003 

 

2,070 

  State

 

(9)

 

358 

 

375 

  

(152)

 

2,361 

 

2,445 

       






Investment tax credit

 

(81)

 

(84)

 

(97)

       

Income taxes – continuing operations

 

2,287 

 

1,615 

 

1,167 

Income taxes – discontinued operations

 

 

 

5,971 

Total

$

2,287 

$

1,615 

$

7,138 



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,

  

2005

 

2004

 

2003

Federal income tax at statutory rate (34%)

$

2,222 

$

1,771 

$

1,254 

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

 

237 

 

189 

 

134 

Investment tax credit

 

(81)

 

(84)

 

(97)

Tax exempt interest

 

(71)

 

(94)

 

(71)

Other

 

(20)

 

(167)

 

(53)

Total provision for income taxes from continuing operations

$

2,287 

$

1,615 

$

1,167 



D. Deferred Income Taxes

The tax effects of temporary differences producing deferred income taxes in the accompanying consolidated balance sheets are as follows:


(Dollars in thousands)

Years ended December 31,

Deferred tax assets:

2005

 

2004

   Environmental

 $    1,932 

 

 $        1,766 

   Self insurance

731 

 

661 

   Storm reserve liability

 408 

 

   Vacation Pay

320 

 

303 

   Other deferred credits

61 

 

105 

   Alternative minimum tax

 

208 

   Allowance for uncollectible accounts receivable

103 

 

102 

   General liability

111 

 

   Rate refund

263 

 

   Pension

286 

 

   Other

46 

 

76 

Total deferred tax assets

$     4,261 

 

$        3,221 


Deferred tax liabilities:

   






   Utility plant related

 $   20,319 

 

$      19,756 

   Deductible intangibles

577 

 

408 

   Under recovery of fuel costs

1,704 

 

634 

   General liability

 

187 

   Storm reserve liability

 

328 

   Pension

 

181 

   Rate case expense

204 

 

265 

   Loss on reacquired debt

85 

 

85 

   Other

 

42 

Total deferred tax liabilities

$   22,895 

 

$    21,886 

    

Net deferred income taxes

$   18,634 

 

$   18,665 


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


(Dollars in thousands)

2005

 

2004

    

Deferred income tax – current

 $        1,066 

 

$          241 

Deferred income tax – long term

17,568 

 

18,424 

Net deferred income tax liability

$      18,634 

 

$       18,665 



E. IRS Audit

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 $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.


7.  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 reserved the following common shares for issuance as of December 31, 2005:


Dividend Reinvestment Plan

68,043 

Employee Stock Purchase Plan

77,690 

Board Compensation Plan

23,704 

Common Stock

3,847,324 


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, 2005.  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 annual dividend rate for the preferred stock is 4.75%.


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, 2005, approximately $7.3 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, 2005 the Company is not in violation of these covenants.


E. Treasury Shares

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.


Statement of Capitalization Comparison

(Dollars in thousands)

Before Treasury Share Restatement

 

December 31,

  

2004

 

2003

Common Shareholders' Equity

    

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,341,984 shares in 2004; 6,318,276 shares in 2003

$

    9,513

$

   9,477

Paid-in capital

 

    6,062

 

   5,744

Retained earnings

 

  31,849

 

 30,638

Treasury stock - at cost (417,128 shares in 2004, 443,860 shares in 2003)

 

  (4,211)

 

 (4,396)

Total common shareholders' equity

$

  43,213

$

 41,463



After Treasury Share Restatement

 

December 31,

  

2004

 

2003

Common Shareholders' Equity

    

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,130,097 shares in 2004; 6,097,478 shares in 2003

$

    9,195

$

   9,146

Paid-in capital

 

    5,806

 

   5,632

Retained earnings

 

  31,849

 

 30,638

Treasury stock - at cost (205,241 shares in 2004, 223,062 shares in 2003)

 

   (3,637)

 

 (3,953)

Total common shareholders' equity

$

  43,213

$

 41,463


F. Employee Stock Purchase Plan

The Company’s Employee Stock Purchase Plan offers common stock at a discount to qualified employees.  The following table shows the number of shares issued under the Plan and the total aggregate consideration received:


Year

Shares

Consideration

2005

22,427 

$ 236,000 

2004

24,164 

$ 220,000 

2003

28,191 

$ 229,000 


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. The following table shows the number of shares issued under the Plan and the total aggregate consideration received:


Year

Shares

Consideration

2005

14,456

$ 193,000

2004

18,513

$ 217,000

2003

20,757

$ 213,000


8.  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 $15.0 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 $14.0 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 $8.0 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 $8.0 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 $10.0 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 $1.9 million in 2005 and $2.0 million in 2004.


Annual Maturities of Long-Term Debt

        
 

Total

2006

2007

2008

2009

2010

2011 &

 

Thereafter

        

Long-term Debt

$50,620

($82)

($82)

$1,327

$1,327

$1,327

$46,803


9.  Notes Payable

In 2004, FPU entered into an amended and restated loan agreement that allows the Company to increase the line of credit (LOC), upon 30 days notice by the Company, to a maximum of $20.0 million and expires on June 30, 2007.  The current outstanding balance on the LOC is $9.6 million with a remaining current available LOC of $2.4 million.  Until April 1, 2003, the Company had a $20.0 million line of credit, with interest at LIBOR plus fifty basis points.  The Company reserves $1.0 million of the LOC to cover expenses for any major storm repairs in its Northwest Florida division.  An additional $250,000 of the LOC is reserved for a ‘letter of credit’ insuring propane facilities.


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

 

Year

Rate

2005

5.3%

2004

3.3%

2003

2.0%


10. 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.  As the older bonds contain ‘make whole’ provisions it would negate any fluctuation in interest rates.  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.


 

2005

2004






 

Carrying

Amounts

Approximate Fair Value

Carrying

Amounts

Approximate Fair Value

Long-term debt

$ 52,500,000

$63,000,000

$52,500,000

$ 63,800,000


11. 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.


Site

Range From

Range To

West Palm Beach

$      10,183,000

$   15,183,000

Sanford

664,000

664,000

Pensacola and Other

129,500

129,500

Total

$      10,976,500

$   15,976,500


The Company currently has $14.0 million reserved as an environmental liability. This amount was approved by the FPSC based on the above projections as a basis for rate recovery.  The Company has recovered $5.1 million from insurance and rate recovery.  The balance of $8.9 million is recorded as a regulatory asset.  On October 18, 2004 the FPSC approved recovery of $9.1 million for environmental liabilities (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 is expected to be incurred before 2010, but will continue for another 20-30 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 Florida Department of Environmental Protection (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. Numerous reports have been submitted by the Company to FDEP describing the results of soil and groundwater sampling conducted at the site.  On November 29, 2005, the Company’s consultant submitted a status report of additional sampling to FDEP, in which the consultant recommended that the Company be permitted to proceed with a feasibility study to evaluate appropriate remedies for the site.  To date, FDEP has not responded to the status report.


Based on the likely acceptability of proven remedial technologies implemented at similar sites in other states, consulting and remediation costs to address the impacts now



characterized at the West Palm Beach site are projected to range from $10 million to $15 million.  This range of costs covers such remedies as in situ solidification, slurry wall and cap containment, air sparge and soil vapor extraction, or in situ chemical oxidation, or some combination of these remedies.


Prior to FDEP’s approval of a final remedy for the site, we are unable to determine the complete extent or cost of remedial action, which may be required. Remediation costs (including attorneys’ fees and costs) for this site are currently projected to range from $10.2 million to $15.2 million.


Sanford Site

The Company owns a parcel of property located in Sanford, Florida, upon which a gasification plant was operated prior to the Company’s 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 (Group) and the United States Environmental Protection Agency (EPA) that obligated the Group to implement a Remedial Investigation and Feasibility Study (RI/FS) task and to pay EPA’s past and future oversight costs for the RI/FS.  The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (RI/FS Participation Agreement).    These agreements governed the manner and means by which all parties were to satisfy their respective obligations under the AOC for the RI/FS task.  The Company agreed to pay approximately 13.7% of the cost for the RI/FS. The Company’s share of the cost of these tasks was previously paid in full.  The RI/FS Participation Agreement was amended on September 18, 2003, to authorize an additional $400,000 to be incurred by the Group to complete the ecological risk assessment and cover EPA oversight costs for the RI/FS.  The Company paid its share ($54,822) of the additional RI/FS funding in November 2003.


On July 5, 2000, EPA issued a Record of Decision (ROD) approving the final remedial action for contaminated soils at the site (OU1 Remedy). The initial estimated cost for the OU1 Remedy described in the ROD ranges from $5.6 million to $5.8 million.  On June 12, 2001, EPA issued a ROD approving the final remedial action for contaminated groundwater at the site (OU2 Remedy).  The present worth cost estimate for the OU2 Remedy is $320,252.


The Company is a party to the Second Participation Agreement entered into by members of the Group on August 1, 2000, as amended through June 19, 2002 (RD/RA Participation Agreement).  The RD/RA Participation Agreement provides for funding the remedial design/remedial action (RD/RA) task for OU1 and OU2.  The Company’s share of costs for implementation of the RD/RA task for OU1 and OU2, including the pre-remedial design fieldwork described below, is 10.5%, providing the total cost of the RD/RA task, including the pre-remedial design fieldwork, does not exceed $6 million.


Based on the pre-remedial design field work performed in 2002-03, it is now anticipated that the final cost of the remedy for OU1 and OU2 will significantly exceed the $6 million combined estimate provided in the RODs for OU1 and OU2. In 2002, the Company paid $210,178 to the Escrow Agent pursuant to a first call for funds under the RD/RA Participation Agreement.  The Company’s remaining obligation under the RD/RA



Participation Agreement is $420,356.  This assumes the Company’s total allocated share remains no greater than 10.5089% of $6 million, as currently set forth in the RD/RA Participation Agreement, as amended through June 19, 2002.  The Company has notified Group members that the Company will oppose any effort by the Group to increase The Company’s share of total RD/RA costs above 10.5089% of the current $6 million cap, since the increased cost is due to the discovery of additional impacted soils on property not owned by the Company.


In addition, the Company will be obligated to pay for a share of EPA’s oversight costs for the RD/RA task for OU1 and OU2.  It is anticipated that the Company’s share of these costs will be 10.5089% of EPA’s total bill.  It is not possible at this time to calculate, to a reasonable degree of certainty, EPA’s oversight cost.  However, based on other similar sites, it would be reasonable to assume such oversight cost to be approximately 20% of the projected RD/RA costs for OU1 and OU2.   Assuming the Company’s maximum exposure for the RD/RA cost for OU1 and OU2 does not exceed 10.5089% of $6 million, a reasonable estimate of the Company’s share of oversight cost would be approximately $125,000.


Prior to EPA’s approval of a final remedy for the site, and the completion of negotiations among members of the Group on the Company’s maximum allocated share, we are unable to determine the complete extent of the Company’s remaining exposure at this site.  Based on the existing Second Participation Agreement, the Company’s remaining exposure for the RD/RA task for OU1 and OU2, EPA’s oversight costs, and the Company’s attorneys’ fees and costs, is projected to be approximately $664,000.


Pensacola site

The Company is the prior owner and 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.  


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 would defer management of the site to FDEP; however, as of this date, 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, 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 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 (SEA) 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.  To date, 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 PCAR of start up and shut down of pipeline operations costs. The Company’s share would be approximately $83,000.


12. Commitments


A. General

To ensure a reliable supply of power 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, 2005, 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 $36.9 million during 2006 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 $260,000. The Company is leasing property from the City of Fernandina Beach in our Northeast division. The total obligation for the duration of this lease is about $134,000 over the next five years. 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 Operating Lease obligations over the next five years.


 

2006

2007

2008

2009

2010

Operating Lease Obligations

$103,000

$53,000

$47,000

$29,000

$26,000




13.

Employee Benefit Plans


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 five Company union contracts that approved this change in 2005. The sixth union contract will be negotiated in 2006.   


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, 2005 and a statement of the funded status as of December 31, of all three years:



Benefit Obligations and Funded Status

   

Years Ended December 31,

   

2005

 

2004

 

2003

(1)

Change in Projected Benefit Obligation

     
 

(a)

Projected Benefit Obligation at the Beginning of the Year

$34,926,383 

 

$31,540,942

 

$28,283,326 

 

(b)

Service Cost

1,195,723 

 

1,084,564 

 

1,012,149 

 

(c)

Interest Cost

2,000,099 

 

1,940,122 

 

1,877,987 

 

(d)

Actuarial (Gain) or Loss

(842,777)

 

1,708,132 

 

1,653,212 

 

(e)

Benefits Paid

(1,514,341)

 

(1,347,377)

 

(1,285,732)

 

(f)

Change in Plan Provisions

584,838 

 

 

 

(g)

Plan Participant Contributions

 

 

 

(h)

Acquisition

 

 

 

(i)

Curtailment

 

 

 

(j)

Settlement

 

 

 

(k)

Special Termination Benefits

 

 

 

(l)

Projected Benefit Obligation at the End of the Year

 $36,349,925 

 

$34,926,383 

 

$31,540,942 

 

(m)

Accumulated Benefit Obligation at the End of the Year

 $31,966,513 

 

$30,518,393 

 

$26,810,146 

(2)

Change in Plan Assets

     
 

(a)

Fair Value of Plan Assets at the Beginning of the Year

 $32,385,214 

 

$31,081,063 

 

$26,953,318 

 

(b)

Actual Return on Plan Assets

2,065,793 

 

 2,651,528 

 

 5,413,477 

 

(c)

Benefits Paid

(1,514,341)

 

(1,347,377)

 

(1,285,732)

 

(d)

Employer Contributions

 

 

 

(e)

Plan Participant Contributions

 

 

 

(f)

Acquisition

 

 

 

(g)

Settlement

 

 

 

(h)

Fair Value of Assets at the End of the Year

$32,936,666 

 

$32,385,214 

 

$31,081,063 

(3)

Net Amount Recognized

     
 

(a)

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

$(3,413,259)

 

$(2,541,169)

 

 $(459,879)

 

(b)

Unrecognized Transition Obligation (Asset)

 

 

 

(c)

Unrecognized Prior Service Cost

4,729,604 

 

4,881,881 

 

5,580,092 

 

(d)

Unrecognized Net (Gain) or Loss

(2,037,678)

 

(1,615,093) 

 

(3,262,796) 

 

(e)

Net Amount Recognized:  (a) + (b) + (c) + (d)

($721,333)

 

$725,619 

 

$1,857,417 






(4)

Amounts Recognized in the Statement of Financial Position

    
 

(a)

Prepaid Benefit Cost

 

$725,619 

 

$1,857,417 

 

(b)

Accrued Benefit Cost

($721,333)

 

 - 

 

 - 

 

(c)

Intangible Asset

 

 - 

 

 - 

 

(d)

Accumulated Other Comprehensive Income

 

 - 

 

 - 

 

(e)

Net Amount Recognized:  (a) + (b) + (c) + (d)

($721,333)

 

 $725,619 

 

 $1,857,417 

(5)

Information for pension plans with an accumulated benefit obligation in excess of plan assets

 

(a)

Projected Benefit Obligation

$36,349,925 

 

$34,926,383 

 

$31,540,942 

 

(b)

Accumulated Benefit Obligation

$31,966,513 

 

$30,518,393 

 

$26,810,146 

 

(c)

Fair Value of Plan Assets

$32,936,666 

 

$32,385,214 

 

$31,081,063 

(6)

Weighted Average Assumptions at the End of the Year

    
 

(a)

Discount Rate

5.90%

 

5.75% 

 

6.25% 

 

(b)

Rate of Compensation Increase

3.00%

 

3.00% 

 

3.50% 


The following table provides the components of net periodic benefit cost for the plans for fiscal years 2005, 2004 and 2003:


Net Periodic Pension Costs

   

Years Ended December 31,

   

2005

 

2004

 

2003

(1)

Service Cost

$1,195,723 

 

$1,084,564 

 

$1,012,149 

(2)

Interest Cost

2,000,099 

 

1,940,122 

 

1,877,987 

(3)

Expected Return on Plan Assets

(2,485,985)

 

(2,591,099)

 

(2,668,854)

(4)

Amortization of Transition Obligation/(Asset)

 

 

(5)

Amortization of Prior Service Cost

737,115 

 

 698,211 

 

711,928 

(6)

Amortization of Net (Gain) or Loss

 

 - 

 

(360,493)

(7)

Total FAS 87 Net Periodic Pension Cost

 1,446,952 

 

1,131,798 

 

572,717 

(8)

FAS 88 Charges / (Credits)

     
 

(a)

Settlement

 

 

 

(b)

Curtailment

 

 

 

(c)

Special Termination Benefits

 

 

 

(d)

Total

     

(9)

Total Net Periodic Pension Cost

$1,446,952 

 

$1,131,798 

 

$572,717 

(10)

Additional Information

     
 

(a)

Increase in Minimum Liability Included in Other Comprehensive Income

$              - 

 

$             - 

 

$            - 

(11)

Weighted Average Assumptions

     
 

(a)

Discount Rate

5.75% 

 

6.25% 

 

6.75% 

 

(b)

Expected Return on Plan Assets

8.50% 

 

8.50% 

 

8.50% 

 

(c)

Rate of Compensation Increase

3.00% 

 

3.50% 

 

4.50% 





Plan Assets

 

 

 

Target

Percentage of Plan

   

Allocation

Assets at December 31

 

 

 

2006

2005

2004

2003

(1)

Plan Assets

    
 

(a)

Equity Securities

60%

67%

69%

61%

 

(b)

Debt Securities

35%

32%

30%

37%

 

(c)

Real Estate

0%

0%

0%

0%

 

(d)

Other

5%

1%

1%

2%

 

(e)

Total

100%

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 50 to 60-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, 2006

 

(a)

Expected Employer Contributions

 

$250,000 

 

(b)

Expected Employee Contributions

 

 $ 0 

(2)

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

 
 

(a)

2006

   

 $1,652,331 

 

(b)

2007

   

 $1,763,865 

 

(c)

2008

   

 $1,842,309 

 

(d)

2009

   

 $1,967,733 

 

(e)

2010

   

 $2,066,326 

 

(f)

2011 – 2015

  

 $12,061,276 





Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2005

 

2004

 

2003

(1)  

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

 $30,016,761

 

 $31,222,154

 

 $32,050,201

(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)


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

None

 

None

 

None

       
       

(5)

Description of Special or Contractual Termination Benefits Recognized During the Period

N/A

 

N/A

 

N/A

       

(6)

Cost of Benefits Described in (5)

N/A

 

N/A

 

N/A

(7)

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

N/A

 

N/A

 

N/A

(8)

Measurement Date Used

December 31, 2005

 

December 31, 2004

 

December 31, 2003




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, 2005:


Benefit Obligations and Funded Status

 

 

 

Fiscal Year Ending

 

 

 

12/31/2005

 

12/31/2004

 

12/31/2003

(1)

Change in Accumulated Postretirement Benefit Obligation

     
 

(a)

Accumulated Postretirement Benefit Obligation at the Beginning of the Year

 $1,925,254 

 

 $1,807,999 

 

 $1,725,639 

 

(b)

Service Cost

 100,054 

 

 70,300 

 

 66,117 

 

(c)

Interest Cost

 127,312 

 

 106,079 

 

 108,849 

 

(d)

Actuarial (Gain) or Loss

 282,812 

 

 32,646 

 

 (23,328)

 

(e)

Benefits Paid

 (135,166)

 

 (119,005)

 

 (91,909)

 

(f)

Change in Plan Provisions

  0 

 

  0 

 

  0 

 

(g)

Plan Participant's Contributions

 43,317 

 

 27,235 

 

 22,631 

 

(h)

Acquisition

  0 

 

  0 

 

  0 

 

(i)

Curtailment

 0 

 

  0 

 

  0 

 

(j)

Settlement

 0 

 

  0 

 

  0 

 

(k)

Special Termination Benefits

 0 

 

  0 

 

  0 

 

(l)

Accumulated Postretirement Benefit Obligation at the End of the Year

 $2,343,583