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Florida Public Utilities Company 10-K 2008
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, 2007

OR

o  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 No.)


401 South Dixie Highway, West Palm Beach, FL

             33401

(Address of principal executive offices,

     

      Zip Code)


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


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


Title of each class

 

Name of each exchange on which registered

Common Stock par value $1.50 per share

 

American Stock Exchange



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

__________________________________________________________________________________

 (Title of class)

__________________________________________________________________________________

(Title of class)



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


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


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  [X] Yes     [  ] No




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


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


Large accelerated filer [  ]                                                        Accelerated filer [  ]

                                                                                                                                                              Non-accelerated filer    [X]                                    Smaller reporting company [  ]

(Do not check if a smaller reporting company)


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 29, 2007, 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 $70,700,000.


On March 18, 2008, 6,187,175 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 13, 2008 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 83,000 customers and our unregulated segment sells propane gas through a wholly owned subsidiary, Flo-Gas Corporation, to approximately 13,000 customers. We also sell merchandise and other service-related products on a limited basis as a complement to the natural and propane gas segments.


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


(1)

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

(2)

Central Florida Division - provides natural and propane gas to customers in Sanford, Deland, Deltona, DeBary, Orange City, Lake Mary, Winter Springs, New Smyrna Beach, Edgewater, Longwood, Port Orange and other areas near these cities.  Our previous West Florida Division, which provides propane gas to customers in Dunnellon, Inglis, Crystal River, Inverness, Brooksville and other areas near these cities, has been consolidated with our Central Florida Division.

(3)

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

(4)

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


Business Environment

The historic growth that has fueled strong demand for natural and propane gas over the last decade has slowed with the slowdown in the new construction housing market and the economy in general. However, interest is growing among those who wish to use natural and propane gas as an environmentally friendly, alternative energy source that is a very reliable source of energy in the event of a power outage. During 2007, the price of natural gas remained stable as no adverse conditions existed to effect pricing. The cost of propane gas increased primarily in response to the unprecedented increase in the price of crude oil.


Historically, our sales in the electric segment have not been impacted by increasing electric costs due to long-term favorable fixed price contracts for purchasing electricity. However, our long-term contracts concluded at the end of 2006 for our Northeast division and at the end of 2007 for our Northwest division. We now have new contracts in place with pricing much closer to current market prices. Our electric selling prices, as a result of these increased fuel costs, significantly increased. Although this does not directly impact our income from operations as increased fuel costs are passed through to the customer, this may decrease the volume of electricity sold, thereby decreasing income from operations.


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 in our natural gas and propane gas areas to complement these segments. For information concerning revenues, operating income and identifiable assets of each of our segments, see Note 13 in Notes to Consolidated Financial Statements.


Natural Gas

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


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


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


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


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


Electric

We provide electricity to our customers in our Northwest and Northeast Florida divisions.  Wholesale electricity is purchased from two suppliers: Gulf Power Company and JEA (formerly Jacksonville Electric Authority).  


During 2006 we completed negotiations with JEA and executed final contracts for the supply of electricity in our Northeast division beginning January 1, 2007 and our Northwest division from Gulf Power Company beginning in January 1, 2008. The rates charged to our customers significantly increased when the new contracts became effective in 2007 and 2008 because the prices are closer to market price. We are unable to estimate what impact higher rates could have on electric consumption in the future, 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, Central and South Florida divisions and can purchase our propane gas supply from several different wholesale companies. Propane gas supply into Florida comes from a diverse assortment of delivery methods such as waterborne barge transports that deliver to port terminals in Tampa and Ft. Lauderdale, and the Dixie Pipeline. Railcar and tractor trailer transport the gas to our storage facilities.  We believe that the propane gas supply infrastructure is adequate to meet the needs of the industry in Florida.


Strategy

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


Competition

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


Rates and Regulation

The natural gas and electric segments are highly regulated by the FPSC.  The FPSC has the authority to regulate our rates, conditions of service, issuance of securities and certain other matters affecting our natural gas and electric operations.  As a result, FPSC regulation has a significant effect on our results of operations.  The FPSC approves rates that are intended to permit a specified rate of return on investment and recovery of prudent expenses.  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 on March 17, 2004 and a natural gas rate increase on November 18, 2004.  We are currently seeking additional electric rate relief in 2008 to recover increased costs including the recent storm preparedness requirements, which were mandated to improve reliability of electric utility systems.

 

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


Prior to the widespread availability of natural gas, we manufactured gas for sale to our customers. We have also purchased land from companies that at one time manufactured gas. The process for manufacturing gas produced by-products and residuals such as coal tar. The remnants of these residuals are sometimes found at former gas manufacturing sites. These sites face environmental regulation from various agencies including the FDEP and EPA on necessary cleanup and restoration. For information on our environmentally impacted sites, please see Item 3, Legal Proceedings.


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 for franchises with certain municipalities for new service areas along with renewing some existing franchises. We continue to provide services to these municipalities and do not anticipate any interruption in our service.


Employees

As of February 1, 2008, we employed 356 employees, including 10 part-time and 5 temporary employees. Of these employees, 174 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). Copies of recent SEC filings as well as 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, plus a permitted return on investment.  Any rate adjustments to recover increased costs or to otherwise improve our profitability must be obtained through a petition, or rate case, filed with the FPSC.  The rates permitted by the FPSC will determine a substantial portion of our revenues 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 or to increase our dividends 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 if our operating costs increase more than our revenues during the period between rate cases.  In addition, even if we decide to file a rate case, our request for a rate adjustment may be rejected.  Third parties to a rate case or the FPSC staff may contend that our current rates are excessive and petition for a decrease in rates. A petition for rate increase by us could be denied on that or another basis.


Our business segments are sensitive to variations in weather.


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


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


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


Natural Gas

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


Electric

The U.S. electric power industry has been undergoing restructuring in many areas. 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 caused 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 could change. 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 it is not regulated, we face significant competition.  Our propane gas business competes directly with other distributors of propane gas, and other sources of energy including natural gas and electric.  If we cannot compete effectively in the propane gas business, whether on the basis of price, customer service, alternative energy sources or otherwise, it would have a material adverse effect on our financial condition and results of operations.


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


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


General economic conditions may adversely affect our segments.


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


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


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


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 expenses.


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


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


Two pipeline suppliers under several contracts expiring at various dates through 2023, transport our natural gas to us.  These contracts have provisions which allow us to extend the terms ranging from 2020 to 2032.  Our electric services are provided by two suppliers under contracts which expire in 2017. If we were to lose any of these contracts we might not be able to replace the corresponding energy source on acceptable terms, if at all.  In addition, in the event of the expiration of the contracts, we might not be able to renew them on favorable terms, if at all.  As a result, the loss of any of these suppliers, the termination of any of these supply contracts, or the non-renewal of any of these supply contracts before or upon their expiration could have material adverse effects on our financial condition and results of operations.


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


We have two pipeline suppliers for natural gas and two electric suppliers under contract for supply through various dates in the future.


The recent renewal of the electricity supply contracts resulted in the cost of electricity increasing significantly over historic prices.  Extensions or renewals of our natural gas contracts could result in the cost of natural gas increasing.  Although these increases are currently passed through to our customers, they could have a significant impact on our customers’ usage. If recovery of fuel costs was denied by the FPSC in the future, it would have a significant impact on our earnings and our financial condition.


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, 2007, we have firm purchase and transportation commitments adequate to supply our expected sales requirements for electricity with contracts that will expire in 2017. Our contract in the Northeast division of the electric segment began January 1, 2007 and expires on December 31, 2017, and our contract with a supplier for the Northwest division began January 1, 2008 and expires on December 31, 2017.

 

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 satisfactory terms, our ability to fund capital expenditures and other commitments will be impaired. Moreover, even if available, the capital may not be available on favorable terms and the cost of such financing could reduce our margins and materially adversely affect our results of operations.


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


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


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


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

 

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


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


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


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


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


We have agreements with our three 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.  Finally, our pension plan contains provisions that upon a change in control an acquirer will be limited in changing the pension plan for a period of time without incurring additional pension expenses for enhanced benefits to pension participants.


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


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


If conservation costs incurred are determined not to be appropriate for recovery through conservation programs and rates, these costs would directly impact our net operating income and could significantly decrease our earnings.

 

The Company participates in energy conservation programs to provide incentives to customers to conserve energy. Costs for these programs are passed directly through to our regulated customers and are recovered through conservation rates.  These programs and costs are reviewed and approved by the Florida Public Service Commission on an annual basis. There can be no assurance the FPSC will continue to approve our recovery of those costs and this could have an adverse effect on our operations.


Item 1B.

Unresolved Staff Comments


None


Item 2.

Properties


We have natural gas, electric and propane gas 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 1,611 miles of pipe located in Central and South Florida. Additionally, we have adequate gate stations to handle receipt of the gas in each distribution system.


In the electric segment, we own 22 miles of electric transmission lines located in Northeast Florida and 1,092 miles of electric distribution lines located in Northeast and Northwest Florida. The distribution lines are installed both under and above ground and many of the coastal locations have under ground facilities. All transmission lines are installed above ground. Additionally, we own various substations and regulator stations that are used in our electric operations.


Our propane gas segment has bulk storage facilities and tank installations on customers' premises. We also have 16 community gas systems that distribute propane gas to customers in specific developments. 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, and South Florida, which are used for our operations and storage of materials. We also have various easements and other assets located throughout our service areas that are utilized by our operations.


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


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


Item 3.   Legal Proceedings


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

 

West Palm Beach Site

The Company is currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by it in West Palm Beach, Florida upon which the Company previously operated a gasification plant. The Company entered into a Consent Order with the FDEP effective April 8, 1991, that requires the Company to delineate the extent of soil and groundwater impacts associated with the prior operation of the gasification plant and to remediate such soil and groundwater impacts, if necessary. The Company completed field investigations for the contamination assessment task in October 2006.  Thereafter, the Company retained an engineering consultant, the RETEC Group, Inc. (RETEC), to perform a feasibility study to evaluate appropriate remedies for the site to respond to the reported soil and groundwater impacts.  On November 30, 2006, RETEC transmitted a feasibility study to the Company and FDEP.  The feasibility study evaluated a wide range of remedial alternatives. The total costs for the remedies evaluated in the feasibility study ranged from a low of $2.8 million to a high of $54.6 million.  Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, consulting/remediation costs are projected to range from $4.6 million to $17.9 million. This range of costs covers such remedies as in situ solidification for the deeper impacts, excavation of surficial soils, installation of a barrier wall with a permeable biotreatment zone, or some combination of these remedies.  


By letter dated May 7, 2007, FDEP provided its comments to the feasibility study, the substance of which was discussed at a meeting between the Company and FDEP on September 14, 2007.  A response to the comments was submitted by the Company to FDEP on October 31, 2007.  We are currently awaiting FDEP's comments to the response. 

 

Based on the information provided in the feasibility study, the remaining legal fees are currently projected to be approximately $295,000. Consulting and remediation costs are projected to range from $4.6 million to $17.9 million. Thus, the Company's total probable legal and cleanup costs for the West Palm Beach site are currently projected to range from $4.9 million to $18.2 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 (collectively, the Group) and the EPA. This AOC obligated the Group to implement a Remedial Investigation/Feasibility Study (RI/FS) and to pay EPA's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (WFS Participation Agreement). Work under the

RI/FS AOC and RI/FS Participation Agreement is now complete and the Company has no further obligations under either agreement.

 

In late September 2006, EPA sent a Special Notice Letter to the Company, notifying it, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the City of Sanford, Florida, collectively with FPUC, "the Sanford Group"), of EPA's selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site.  The total estimated remediation costs for the Sanford gasification plant site are now projected to be $12.9 million. The Sanford Group was further advised that EPA was willing to negotiate a consent decree with the Sanford Group to provide for the implementation of the final remedy approved by EPA for the site. 


In January 2007, the Company and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by EPA for the site.  The Company's share of remediation costs under the Third Participation Agreement is set at a maximum of $650,000, providing the total cost of the final remedy does not exceed $13 million.  At present, it is not anticipated that the total cost will exceed $13 million.  If it does, the Sanford Group members have agreed to negotiate in good faith at such time that it appears that the total cost will exceed $13 million for the allocation of the additional cost.  The Company has advised the other members of the Sanford Group that the Company is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by the Company in the Third Participation Agreement.

 

On June 26, 2007, the Sanford Group transmitted to EPA a Consent Decree signed by all Group Members, providing for the implementation by the Sanford Group of the remedy selected by EPA for the site.  The consent decree is currently being circulated within EPA and the United States Department of Justice for execution by those parties.  Thereafter, the consent decree will be lodged with the federal court in Orlando, Florida.  Following a public comment period, it is anticipated that the federal court will enter the consent decree.  The Sanford Group will then be obligated to implement the remedy approved by EPA for the site. 

 

Remaining legal fees/costs are currently projected to be approximately $77,000. The Company's obligation under the Third Participation Agreement is $650,000. Thus, the Company's total probable legal and cleanup costs for the Sanford site are currently projected to be approximately $727,000. 


Pensacola Site

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


Consulting and remediation costs are projected to be $26,000 and legal fees are projected to be $4,000, for total probable costs for the Pensacola site of $30,000.


Key West Site

From 1927-1938, we owned and operated a gasification plant in Key West, Florida. The plant discontinued operations in the late 1940s; the property on which the plant was located is currently used for a propane gas distribution business. In March 1993, a Preliminary Contamination Assessment Report (PCAR) was prepared by a consultant jointly retained by the current site owner and the Company and was delivered to FDEP. The PCAR reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, FDEP notified us that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." FDEP then referred the matter to its Marathon office for consideration of whether additional work would be required by FDEP's district office under Florida law.


Consulting and remediation costs are projected to be $83,000 and legal fees are projected to be $10,000, for total probable costs for the Key West site of $93,000.



Item 4.

Submission of Matters to a Vote of Security Holders


None


 


 

Executive Officers of the Registrant


The following sets forth certain information about the executive officers of the Company as of February 17, 2008.


Name

Age

Position

Date

 

 

 

 

John T. English

64

Chairman of the Board

2006 - Present

 

 

Chief Executive Officer

1998 - Present

 

 

President

1997 - Present

 

 

Chief Operating Officer

1997 - 2000

 

 

 

 

Charles L. Stein

58

Chief Operating Officer

2001 - Present

 

 

Senior Vice President

1997 - Present

 

 

 

 

George M. Bachman

48

Corporate Secretary

2004 - Present

 

 

Chief Financial Officer

2001 - Present

 

 

Treasurer

2001 - Present

 

 

 

 


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


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


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


Each of these executive officers has an employment agreement dated March 31, 2006 with a term through March 30, 2009, which can be renewed by the Board prior to the expiration of the agreement subject to 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 as reported by the American Stock Exchange for the most recent two years were as follows:

 

 

2007

 

2006

 

Stock Prices

Dividends

 

  Stock Prices

Dividends

Quarter ended

Low

 

High

Declared

 

Low

 

High

Declared

March 31 

$11.90 

 

$13.50 

$0.1075 

 

$13.25 

 

$14.50 

$0.1033 

June 30 

11.01 

 

12.91 

0.1125 

 

11.86 

 

14.40 

0.1075 

September 30 

 11.15 

 

12.49 

0.1125 

 

12.61 

 

14.42 

0.1075 

December 31 

11.24 

 

12.83 

0.1125 

 

13.10 

 

14.05 

0.1075 


As of February 5, 2008, there were approximately 3,985 holders of record of our common shares.


We intend 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, 2007, approximately $9.6 million of retained earnings were free of such restriction and 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

41,623*

Equity compensation plans not approved by security holders

    -

Total

                           41,623

 

 

* This includes 17,564 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 24,059 shares for the Employee Stock Purchase Plan.


Item 6.

Selected Financial Data


(Dollars in thousands, except per share data)

Years Ended December 31,

 

2007 

 

2006 

 

2005 

 

2004(3) 

 

2003 (1)(3)

Revenues  (2)

136,542 

134,781 

130,285 

110,131 

102,822 

 

 

 

 

 

 

 

 

 

 

 

Gross profit  (2)

48,721 

48,810 

47,481 

40,781 

37,832 

Earnings:

 

 

 

 

 

 

 

 

 

 

Continuing operations

3,301 

4,169 

4,248 

3,594 

2,522 

Discontinued operations (1)

 

 

 

 

 

9,901 

Net income

3,301 

4,169 

4,248 

3,594 

12,423 

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share (basic and diluted):

 

 

 

 

 

 

 

 

 

 

Continuing operations

 0.54 

0.69 

0.71 

0.60 

0.43 

Discontinued operations (1)

 

 

 

 

 

1.69 

Total

0.54 

0.69 

0.71 

0.60 

2.12 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per common share

0.45 

0.43 

0.41 

0.40 

0.39 

 

 

 

 

 

 

 

 

 

 

 

Total assets   (2)

192,344 

181,234 

 182,666 

170,503 

160,944 

Utility plant – net

138,372 

129,211 

123,061 

117,191 

107,942 

Current debt

12,531 

3,466 

9,558 

5,825 

2,278 

Long-term debt

49,363 

50,702 

50,620 

50,538 

50,454 

Common shareholders' equity

48,946 

47,572 

45,503 

43,213 

41,463 


Note to the Selected Financial Data:

 

(1)

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

  (2)   Prior period amounts have been reclassified to conform to current year presentation.

(3)

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.


Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operation


RESULTS OF OPERATIONS


General

The effects of seasonal weather conditions, 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, have a significant impact on income.


Revenues and Gross Profit Summary

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

 

Revenues and Gross Profit

(Dollars in thousands)

 

Years Ended December 31,

 

2007

2006

2005

Natural Gas

 

 

 

Revenues

$64,850 

$71,139 

$69,094 

Cost of fuel and other pass through costs

38,251 

43,909 

42,815 

Gross Profit

$26,599 

$27,230 

$26,279 

   Units sold: (MDth)

6,042 

6,230 

 6,224 

   Customers (average for the period)

51,589 

51,211 

50,246 

Electric

 

 

 

Revenues

$55,521 

$48,527 

$47,450 

Cost of fuel and other pass through costs

41,142 

34,259 

33,352 

Gross Profit

$14,379 

$14,268 

$14,098 

   Units sold: (MWH)

810,604 

849,124 

814,353 

   Customers (average for the period)

31,074 

30,635 

30,244 

Propane Gas

 

 

 

Revenues

$16,171 

$15,115 

$13,741 

Cost of fuel

8,428 

7,803 

6,637 

Gross Profit

$ 7,743 

$7,312 

$7,104 

Units sold:  (MDth)

597 

 621 

640 

    Customers (average for the period)

13,140 

13,048 

12,375 

Consolidated

 

 

 

Revenues

$136,542 

$134,781 

$130,285 

Cost of fuel and other pass through costs

87,821 

85,971 

82,804 

Gross Profit

$ 48,721 

$ 48,810 

$ 47,481 

Customers (average for the period)

95,803 

94,894 

92,865 


Natural Gas

Natural gas revenues decreased $6.3 million, or 9% in 2007 over 2006. As the cost of natural gas continued to decline, the revenue to recover the fuel costs, which are passed through to customers, decreased by $5.7 million.  Our gross profit, which excludes expenses directly passed through to customers, decreased by $631,000 or 2%.  Although customer growth was up in 2007 compared to 2006, we experienced a 3% decrease in units sold primarily due to milder weather.


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


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

 

Electric

Electric revenues increased $7.0 million or 14% in 2007 over 2006.  Cost of fuel and other costs that were passed through to customers contributed to $6.9 million of the increase as a result of the new fuel contracts effective January 1, 2007 in our Northeast division. Gross profit, which excludes the fuel and other costs passed through in revenue, was flat compared to 2006.  Although the number of customers increased by 1%, there was a marginal decrease in units sold, excluding units sold to industrial customers, as a result of possible conservation measures taken by our customers due to the fuel cost increases.


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


Propane Gas

Propane revenues increased $1.1 million, or 7%. Higher fuel costs caused $625,000 of this increase. Gross profit increased $431,000 or 6% in 2007 compared to 2006.  We experienced a 4% decrease in units sold to customers due to warmer weather; however, this was offset by increased rates and service fees.


Propane revenues increased $1.4 million, or 10% and gross profit increased $208,000 or 3% in 2006 compared to 2005.  Revenues increased primarily due to rising fuel costs. Although customers increased by 5% in 2006, the usage per customer declined by 8% contributing to a decrease of 3% in units sold.  Warmer weather was the primary reason for this decrease in usage per customer in 2006 compared to 2005. The increase in gross profit was minimal when compared to 2005 primarily due to pre-buy gains of $383,000 realized in 2005 but not in 2006.


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,

 

2007 

2006

             2005

Natural gas

$   21,951 

$   21,112 

$   20,230 

Electric

11,726 

   11,215 

     10,596 

Propane gas

6,223 

     6,306 

     6,018 

Total Operating Expenses

$ 39,900 

 $   38,633 

 $   36,844 


Natural Gas

Natural gas operating expenses increased $839,000, or 4%, in 2007 as compared with 2006. Administrative expenses accounted for $503,000 of the increase and are discussed in a separate section below. Depreciation expense increased $291,000 due in part to construction of mains and additional meters to distribute gas to new developments in South Florida along with increasing capacity requirements for existing customers. As a result of a new management focus to offset the effects of the construction industry and housing market slowdown, we increased our efforts to provide improved customer service and upgraded our existing meter equipment resulting in an increase of related expenses of $287,000. This increase was offset by a $245,000 reduction in sales expense resulting from the elimination of three sales positions due to cut backs related to the slowdown in the housing market. 


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


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


Electric

Electric operating expenses increased $511,000, or 5%, in 2007 as compared with 2006. Administrative expenses accounted for $437,000 of the increase and are discussed in a separate section below. Due to a quiet hurricane season this year, we were able to re-direct work efforts and make some operating and safety improvements of our overall electric system, which increased operating expenses by $136,000. As a result of a milder storm season, we experienced a decrease in weather-related maintenance of conduct, lines and poles expenses of $184,000.


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


Propane Gas

Propane gas operating expenses decreased $83,000, or 1%, in 2007 as compared with 2006. The major reason for the decrease was lower selling expenses as a result of a drop in demand from the slowdown of new construction in South Florida. Additionally, the Summer Glen project was converted from a propane system to natural gas in the fourth quarter of 2007 causing all related expenses to shift to our natural gas segment.

 

Propane gas operating expenses increased $288,000, or 5%, in 2006 as compared with 2005. Depreciation expense increased $99,000 for the addition of plant assets including a propane gas delivery system to increase the efficiency of our deliveries and improve our overall customer satisfaction. Aging accounts receivable, slowing housing economy and increasing revenues contributed to an increase in our bad debt expense over 2005.


Administrative Expenses

Administrative expenses increased $1,005,000, or 11%, in 2007 over 2006. Several unusual claims resulting in settlements were the primary reasons for the $796,000 increase to our liability expenses. These claims were for several general liability suits related to auto, employment and liability issues. In addition, our payroll expenses increased $163,000 as a result of annual pay raises.


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


Total Other Income and Deductions

Other income and deductions include revenues and expenses from sales, installation, and service of merchandise; gains and losses on disposal of property; interest expense; and miscellaneous income and expenses. Merchandise sales and installation and interest expenses are the largest components of this section and are discussed below.


Merchandise and Services Revenue and Expenses

Merchandise and services revenue and expense decreased by $1,145,000 and $1,270,000, respectively, although our overall profit increased $125,000. A lower number of product installations actually improved our profit margin on the installation side of our business. We had less customer owned tank installations and we discontinued generator sales, both are historically less profitable.  We continue to face a slowdown in the construction industry and housing market to an even greater degree in 2007, and this along with a quiet hurricane season, dramatically reduced the demand for new merchandise. Management does not anticipate the housing market will rebound in 2008, and expects reduced sales levels to continue.  


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

 

Interest Expense

Interest expense consists of interest on bonds, short-term borrowings, over earnings and customer deposits. In 2007, interest expense increased $262,000, including $76,000 interest on our 2005 over-earnings that was approved by the Commission for the natural gas segment and interest on our increased credit line for additional funding of over $3 million to purchase the new site to relocate our South Florida operations facility.  


Other

Other non-operating income increased $84,000 compared to the prior year primarily due to income generated from a sale of land at Rainbow Lakes.


Income Taxes

Income tax expense decreased in 2007 by $541,000 over 2006 due to lower taxable income.


Liquidity and Capital Resources


Summary of Primary Sources and Uses of Cash

(Dollars in thousands)

 

Year Ended December 31,

 

2007 

2006

2005

Sources of Cash:

 

 

 

Operating activities, including working capital changes

$14,526 

$20,090 

$10,213 

Net proceeds on short-term debt

7,656 

3,733 

Other sources of cash

923 

1,179 

1,214 

Uses of Cash:

 

 

 

Construction expenditures

16,740 

13,116 

12,441 

Dividends paid

2,681 

2,551 

2,448 

Net payment on short-term debt

6,092 

Other uses of cash

290 

121 

75 

     Net source (use) of cash

$ 3,394

$   (611)

$     196


Cash Flows

Operating Activities

Net cash flow provided by operating activities decreased in 2007 by approximately $5.6 million compared to 2006.  We had a $6.4 million decrease related to refunding the prior over-recovery of fuel and other pass through costs.   


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


Investing Activities

Capital expenditures increased in 2007 compared to 2006 by approximately $3.6 million. The major component of the increase was the purchase of land for approximately $3.5 million for the future site of our South Florida operations facility.

 

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


Financing Activities

Short-term borrowings increased by approximately $7.7 million in 2007. The main reasons for the increase were the purchase of land for our South Florida operations center and the repayment of over-recoveries of fuel costs from prior periods.


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


Capital Resources

We have a $12 million line of credit with Bank of America, which expires on July 1, 2008. Upon 30 days notice we can increase the line of credit to a maximum of $20 million. The line of credit contains affirmative and negative covenants that, if violated, would give the bank the right to accelerate the due date of the loan to be immediately payable. The covenants include certain financial ratios.  All ratios are currently met and management believes we are in full compliance with all covenants and anticipates continued compliance.  In March 2008 we amended the 2007 line of credit to increase the maximum credit line to $26 million and to extend the expiration of the line to 2010. See below, ”Outlook and Subsequent Events”.


We reserve $1 million of the line of credit to cover expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane gas facilities. As of December 31, 2007, the amount borrowed on the line of credit was $11.1 million. The line of credit, long-term debt and preferred stock as of December 31, 2007 comprised 56% of total debt and equity capitalization.


Historically we have 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 continue to review our financing options including increasing our short-term line of credit, issuing equity, or issuing debt. The choice of financing will be dependent on prevailing market conditions, the impact to our financial covenants and the effect on income. The timing of additional funding will be dependent on projected environmental expenditures, building of the South Florida operations facility, pension contributions, and other capital expenditures.


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, 2007, such calculation would permit the issuance of approximately $45.9 million of additional bonds.


On October 25, 2007 we received approval from the FPSC to issue and sell or exchange an additional amount of $45 million in any combination of long-term debt, short-term notes and equity securities and/or to assume liabilities or obligations as guarantor, endorser or surety during calendar year 2008. In the event we choose not to proceed in 2008 with such a financing, we may seek approval from the FPSC in 2008 for any possible financing in 2009.

 

We have $3.4 million in invested funds for payment of future environmental costs. We expect to use some or all of these funds in 2008.


There is approximately $6.1 million in receivables from the 2003 sale of our water assets, of which an estimated installment of $300,000 is anticipated to be received in 2009.  The remaining balance of $5.8 million will be collected in 2010.  The present value of this receivable is $5.9 million.


Capital Requirements

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


Capital expenditures are expected to be lower in 2008 compared to 2007 by approximately $1.5 million because the anticipated $2.0 million for the construction of the building for the new South Florida operations facility in 2008 is lower than the $3.5 million related to the purchase of land for the new South Florida operations facility that occurred in 2007.


Cash requirements will increase significantly in the future due to environmental cleanup costs, sinking fund payments on long-term debt and pension contributions. Environmental cleanup is forecast to require payments of approximately $1.4 million in 2008, with remaining payments, which could total approximately $13.7 million, beginning in 2009. Annual long-term debt sinking fund payments of approximately $1.4 million will begin in 2008 and will continue for eleven years. Based on current projections, we will make a voluntary contribution in our defined benefit pension plan of $250,000 in 2008 for the preceding year and will continue for future years to make contributions as required by the Pension Protection Act funding rules.


Based on our current expectations for 2008 cash needs, including the construction of our South Florida operations facility, we may rely on the increased line of credit or may choose to consider equity or debt financing. The need and timing will depend upon operational requirements, the timing of environmental expenditures, pension contributions and construction expenditures.  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 after 2008.  We continue to assess the feasibility of refinancing our mortgage bonds. If refinancing is deemed cost effective, we may re-issue a bond for additional principal. Many of our bonds contain prepayment penalties which effectively make refinancing impractical. There can be no assurance, however, that equity or debt transaction financing will be available on favorable terms or at all when we make the decision to proceed with a financing transaction.


Outlook and Subsequent Events


Electric Power Supply Contracts

In our Northeast division, we entered into a new long-term supply agreement that began January 1, 2007 and will expire December 31, 2017. We executed a contract for the provider of electricity in our Northwest division in December 2006 and the contract was approved by the FPSC in July 2007.  This contract will be for the purchase of electricity beginning January 1, 2008 and will expire December 31, 2017.

 

The new supply contracts have resulted in variable rates closer to market, which may cause our customers’ bills to double during 2008 over past fixed prices. We are unable to precisely estimate what impact the higher rates could have on electric consumption but we expect there could be as much as a 10% reduction in sales.


Over-earnings and Storm Reserve-Natural Gas Segment

On August 14, 2007 the Commission finalized the disposition of 2005 over-earnings for the natural gas segment of $666,000, plus interest of $76,000.


2005 Natural Gas Over-Earnings Summary

 (Dollars in thousands)

 

December 31, 2007

 

Before Application of PSC Order

2007 Adjustment

After Application of PSC Order

Current Assets:

 

 

 

Other regulatory assets-storm reserve current

$             116

$         (116)

$                0

 

 

 

 

Assets:

 

 

 

Other regulatory assets-storm reserve

13

(13)

0

 

 

 

 

Capitalization and Liabilities:

 

 

 

Over-earnings liability

768

(742)

26

Regulatory liability -storm reserve

1,774

                  613

2,387

 

 

 

 

Revenues:

 

 

 

Natural Gas Revenue

64,866

(16)

64,850

 

 

 

 

Other Income and (Deductions):

 

 

 

Interest expense on customer deposits and other

(659)

(76)

(735)


The Commission ordered the 2005 over-earnings to be applied against the regulatory asset - storm reserve in our natural gas operations and the storm surcharge collected from customers. The remaining over-earnings was used to fund a storm reserve for future storm costs.  The storm reserve for our natural gas division as of December 31, 2007 is approximately $613,000.


We recorded estimated 2006 over-earnings for the natural gas segment of $25,000. Interest accrued on this estimated over-earnings as of December 31, 2007 is $1,300. This liability is included in the over-earnings liability on our balance sheet. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations. Estimates may be revised as expectations change and factors become known and determinable.


Our 2006 estimates of our over-earnings liabilities could change upon the FPSC finalization of our earnings expected during 2008. The FPSC determines the disposition of over-earnings with alternatives that include refunds to customers, funding storm or environmental reserves, or reducing any depreciation reserve deficiency.


Storm Preparedness Expenses

Regulators continue to focus on hurricane preparedness and storm recovery issues for utility companies. Newly mandated storm preparedness initiatives could impact our operating expenses and capital expenditures in 2008. The current forecast is not expected to exceed additional annual expenditures of approximately $590,000. It is possible that additional regulation and rules will be mandated regarding storm related expenditures over the next several years. We requested that the FPSC allow us to recover the cost of the newly mandated storm preparedness initiatives and to defer these storm-related expenditures until we receive recovery through a rate increase. The recovery of these costs and revisions, if any, of our storm preparedness initiatives will be considered in our upcoming electric rate proceeding in the first quarter of 2008.


Land Purchase

We purchased land for $3.5 million in July 2007 for a new South Florida operations facility.  We are in the process of preparing plans for a building on this property and expect to begin construction in 2008.  


Summer Glen Conversion

In September we successfully completed the conversion of 491 homes from propane to natural gas within a large gated community in our Central Florida Division.  The conversion will allow customers to take advantage of lower natural gas rates and provide the Company with greater customer retention. The community is still in the process of building new homes and when completed will result in 1,000 residential natural gas accounts.


Medical Insurance

We continue to experience increases in our medical insurance costs. Based on negotiations, management expects an increase of approximately 13% or $300,000 in 2008 over 2007.


Electric Base Rate Proceeding

We filed a request with the FPSC in the third quarter of 2007 for a base rate increase in our electric segment. This request includes recovery of increased expenses and capital expenditures since our last rate proceeding in 2004, as well as additional storm-preparedness expenditures as discussed above. Finalization of this request and approval, if any, of an electric base rate increase would not occur until the second quarter of 2008.


Interim rate relief for partial recovery of the increased expenditures was approved by the Commission on October 23, 2007. Interim rates which should produce additional annual revenues of approximately $800,000 went into effect for meter readings on and after November 22, 2007. The permanent rates may differ from the interim rates, and the interim rates are collected subject to refund with interest.


If the Commission approves partial recovery instead of full recovery of the requested rate increase including recovery of increased expenses, return on capital expenditures or our requested cost of common equity, the impact to our 2008 and future net operating income in our electric segments could be lower than anticipated.


Electric Depreciation Study

On January 29, 2008, the Commission approved new electric depreciation rates effective January 1, 2008 that are expected to increase depreciation expense by approximately $300,000 in 2008. Management expects the Commission will approve recovery of this increased depreciation expense in our 2008 electric rate proceeding.

 

Regulatory Asset/Liability - Retirement Plans

The Company filed a petition with the Florida Public Service Commission in 2008 for approval to defer a portion of our costs associated with FASB 158 in a regulatory asset or liability that would have otherwise been recorded in equity.  In February 2008, the FPSC approved deferral of these costs associated with our regulated pension and retiree’s medical plan.


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

$52,490

$1,409

$2,818

$2,818

$45,445

Long-term Debt Interest

59,955

3,880

7,349

6,800

41,926

Unrecognized Tax Benefits

268

268

-

-

-

Natural Gas and Propane Gas Purchase Obligations

64,791

41,865

12,548

5,255

5,123

Electric Purchase Obligations

282,800

26,800

53,600

53,600

148,800

Other Purchase Obligations

4,220

1,771

2,356

29

64

Total

$464,524

$75,993

$78,671

$68,502

$241,358


Long-term Debt Obligations

The Long-term debt obligations are principal amounts.

 

Long-term Debt Interest

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


FIN 48 Obligations

We performed an assessment of our uncertain tax positions as of December 31, 2007, and recognized a FIN 48 liability for various tax positions relating solely to the timing of various tax deductions.  These tax positions relate to the 2004 through 2007 tax years.


Natural Gas and Propane Gas Purchase Obligations

Our Natural Gas Purchase Obligations consist of those contracts necessary to arrange for the purchase of natural gas to meet our demand requirements as well as those contacts necessary to arrange for the interstate and intrastate transport to our gate stations.  In addition, our Propane Gas Purchase Obligations consist of those contracts necessary to arrange for the purchase and delivery of propane gas to our storage facilities to meet demand requirements.


Electric Purchase Obligations

During 2006 we completed negotiations and executed final contracts for the supply of electricity in our Northeast division beginning January 1, 2007 and our Northwest division beginning in January 1, 2008. The new contracts, effective in 2007 and 2008, significantly increased our contractual obligations over prior years due to a minimum purchase provision.


Purchase Obligations

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

 

Pension, Medical Postretirement and Other Obligations

Our pension plan continues to meet all funding requirements under ERISA regulations; however, under current actuarial assumptions contributions may be required as early as 2009.  Current projections indicate that we will make a voluntary contribution of $250,000 in 2008 for our 2007 pension plan year and will continue in future years to make contributions as required by the Pension Protection Act funding rules. These payments are not included in the Contractual Obligations table.


Environmental cleanup is anticipated to require approximately $1.4 million in 2008, the remainder to be paid in following years. These payments are not included in the Contractual Obligations table.


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


Dividends

We have historically paid dividends. It is our intention 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.


Line of Credit

In March 2008, we amended our line of credit with Bank of America to allow us, upon 30 days notice, to increase our maximum credit line to $26 million from $20 million. The new agreement expires July 1, 2010. The amendment also reduces the interest rate paid on borrowings by 0.10% or 10 basis points. The new interest rate terms, if effective for 2007, would have reduced our overall average interest rate for 2007 to approximately 5.7% from 5.8% as of December 31, 2007.


Other


Impact of Recent Accounting Standards


Financial Accounting Standard No. 157

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements”. This Statement clarifies fair value as the market value received to sell an asset or paid to transfer a liability, that is, the exit value, and applies to any assets or liabilities that require recurring determination of fair value.  The measurement includes any applicable risk factors and does not include any adjustment for volume.  On February 12, 2008, the FASB issued proposed FASB Staff Position No. FAS No. 157-2, “Effective Date of FASB Statement No. 157” which defers the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) to fiscal years beginning after November 15, 2008. The Company expects to adopt SFAS No. 157 effective January 1, 2009. The Company is still evaluating the impact adoption of this Statement will have on our financial condition or results of operation.


Financial Accounting Standard No. 159

In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”. This Statement permits measurement at fair value of certain firm commitments, nonfinancial insurance contracts and warranties, host financial instruments and recognized financial assets and liabilities, excluding consolidating investments in subsidiaries, consolidating variable interest entities, various forms of deferred compensation agreements, leases, depository institution deposit liabilities and financial instruments included in shareholders’ equity.  This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company does not expect to adopt SFAS No. 159.

 

Financial Accounting Standard No. 160

In December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”.  This standard requires noncontrolling ownership interests be disclosed separately in equity, separate disclosure of income contributable to each party, changes in controlling interests be reported consistently, and deconsolidation be measured at fair value. As the company does not currently have any noncontrolling interests this standard will not have an impact on our financial condition or results of operations until the Company acquires a noncontrolling interest.

 

Financial Accounting Standard No. 141R

In December 2007, the FASB issued a revision to Statement No. 141, “Business Combinations”. This statement is effective prospectively for business combinations occurring on or after January 1, 2009 for our company.  This revision broadens the scope of a business combination to include transactions in which no consideration has been exchanged, sets the acquisition date as the date control is obtained, replaces the cost allocation method with fair value method to assign values to assets and liabilities assumed, requires restructuring costs to be recorded separate of the business combination, and does not permit deferral of contractual contingencies at acquisition date.  As this revision is adopted prospectively and all qualifying future business combinations would be evaluated under the new provisions, the effects on our results of operations will depend on the nature and size of any future acquisitions.


Critical Accounting Policies and Estimates


Regulatory Accounting

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


Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that restricts our ability to establish prices to recover specific costs, and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation.  We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate.  Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, we believe that our regulatory assets are probable of recovery.

 

Use of Estimates

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


·

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

·

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

·

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

·

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

·

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

·

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

·

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


Revenue Recognition

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


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

 

Effects of Inflation

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


Environmental Matters

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


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 construction of the South Florida operations facility, we may choose to consider an equity or debt financing.

·

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

·

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

·

Storm hardening related expenditures may be necessary in 2008 and the total cost may be significant. We may receive recovery for these expenditures.

·

Our 2006 over-earnings liability in natural gas will materialize as estimated.

·

We expect higher fuel costs in our electric divisions could have an impact on electric consumption.

·

The Summer Glen customer growth will occur as expected.

·

Finalization and approval of an electric base rate increase is expected in the second quarter of 2008.

·

Medical expenses are expected to increase in 2008.

·

Management does not anticipate the housing market will rebound in 2008.


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 decided not to implement a hedging plan combining purchasing caps and swaps. We had tentatively decided that on a rolling four-quarter basis, we would purchase a “cap” on approximately one-third of our forecast propane volume purchases and pre-buy or hedge with a swap one-third of our forecast anticipated propane purchases.  Instead, we decided to use a combination of pre-purchasing propane gas and purchasing at fluctuating market prices. As of December 31, 2007, we had not entered into any hedging activities, and we do not anticipate entering into hedging activities in 2008.


We have no exposure to equity risk, as we do not hold any material equity instruments. Our exposure to interest rate risk is limited to investments held for environmental costs, the long-term notes receivable from the sale of our water division 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 approximately $11.1 million at the end of December 2007. 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 (pre-payment penalties that charge for lost interest), which render refinancing impracticable until sometime after 2010.


Our non-interest bearing long-term receivable from the sale of the water operations was discounted at 4.34%. A hypothetical 0.5% (50 basis points) increase in the interest rate used would change the current fair value from $5.9 million to $5.8 million.


In 2007, 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 $60 million to $63 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 $11.1 million on December 31, 2007 and $3.5 million on December 31, 2006.  A hypothetical 1% increase in interest rates would have resulted in a decrease in annual earnings for 2007 by $110,000 and for 2006 by $35,000, 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

 

2007

 

2006

 

2005

Natural gas

              64,850

$

71,139 

69,094 

Electric

 

55,521 

 

48,527 

 

47,450 

Propane gas

 

16,171 

 

15,115 

 

13,741 

Total revenues

 

136,542 

 

134,781 

 

130,285 

Cost of Fuel and Other Pass Through Costs

 

87,821 

 

85,971 

 

82,804 

Gross Profit

 

48,721 

 

48,810 

 

47,481 

Operating Expenses

 

 

 

 

 

 

Operation

 

25,178 

 

24,422 

 

23,143 

Maintenance

 

3,402 

 

3,484 

 

3,566 

Depreciation and amortization

 

8,286 

 

7,742 

 

7,266 

Taxes other than income taxes

 

3,034 

 

2,985 

 

2,869 

Total operating expenses

 

39,900 

 

38,633 

 

36,844 

Operating Income

 

8,821 

 

10,177 

 

10,637 

Other Income and (Deductions)

 

 

 

 

 

 

Merchandise and service revenue

 

3,177 

 

4,322 

 

4,590 

Merchandise and service expenses

 

(2,801)

 

(4,071)

 

(4,664)

Other income

 

690 

 

620 

 

569 

Other deductions

 

(19)

 

(33)

 

(29) 

Interest expense on long-term debt

 

(3,948)

 

(3,949)

 

(3,949)

Interest expense on short-term borrowings

 

(187)

 

(108)

 

(79)

Interest expense on customer deposits and other

 

(735)

 

(551)

 

(540)

Total other deductions – net

 

(3,823)

 

(3,770)

 

(4,102)

Earnings Before Income Taxes

 

             4,998 

 

6,407 

 

6,535 

Income Taxes

 

(1,697)

 

(2,238)

 

(2,287)

Net Income

 

3,301 

 

4,169 

 

4,248 

Preferred Stock Dividends

 

29 

 

29 

 

29 

Earnings for Common Stock

$

3,272 

4,140 

4,219 

Earnings Per Common Share (basic and diluted)

$

.54 

.69 

.71 

Dividends Declared Per Common Share

$

.45 

.43 

.41 

Average Shares Outstanding

 

6,039,767 

 

5,993,589 

 

5,952,684 



See Notes to Consolidated Financial Statements




CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

 

December 31,

ASSETS

 

2007

 

2006

Utility Plant

 

 

 

 

Natural gas

$

104,770

$

95,393

Electric

 

76,520

 

72,776

Propane gas

 

17,141

 

17,153

Common

 

3,953

 

3,646

Total

 

202,384

 

188,968

Less accumulated depreciation

 

64,012

 

59,757

Net utility plant

 

138,372

 

129,211

 

 

 

 

 

Current Assets

 

 

 

 

Cash

 

3,478

 

84

Accounts receivable

 

12,269

 

12,199

Notes receivable

 

298

 

298

Allowance for uncollectible accounts

 

(326)

 

(429)

Unbilled receivables

 

1,879

 

1,957

Inventories (at average or unit cost)

 

4,251

 

4,120

Prepaid expenses

 

861

 

963

Under-recovery of fuel costs

 

-

 

862

    Deferred charges – current

 

125

 

238

    Other regulatory assets – storm reserve current

 

-

 

228

    Other regulatory assets- environmental, current

 

456

 

456

    Investments held for environmental costs - current

 

3,444

 

3,364

    Deferred income taxes - current

 

949

 

418

Total current assets

 

27,684

 

24,758

 

 

 

 

 

Other Assets

 

 

 

 

 

 

 

 

 

Other regulatory assets – storm reserve

 

-

 

55

Other regulatory assets – environmental

 

7,197

 

7,815

Other regulatory assets – retirement plans

 

-

 

587

Long-term receivables and other investments

 

5,622

 

5,740

Deferred charges

 

6,634

 

6,258

Goodwill

 

2,405

 

2,405

Intangible assets (net)

 

4,430

 

4,405

Total other assets

 

26,288

 

27,265

Total

$

192,344

$

181,234


  See Notes to Consolidated Financial Statements




CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)    

 

 

December 31,

CAPITALIZATION AND LIABILITIES

 

2007

 

2006

Capitalization

 

 

 

 

Common shareholders' equity

$

48,946

$

47,572

Preferred stock

 

600

 

600

Long-term debt

 

49,363

 

50,702

Total capitalization

 

98,909

 

98,874

 

 

 

 

 

Current Liabilities

 

 

 

 

Line of credit

 

11,122

 

3,466

Accounts payable

 

9,901

 

10,279

Long term debt - current

 

1,409

 

-

Insurance accrued

 

218

 

181

Interest accrued

 

1,163

 

789

Other accruals and payables

 

2,729

 

2,410

Environmental liability - current

 

1,379

 

613

Taxes accrued

 

2,168

 

1,180

Over-earnings liability

 

26

 

722

Over-recovery of fuel costs

 

2,761

 

3,656

Over-recovery of conservation

 

446

 

355

Customer deposits

 

10,547

 

9,608

Total current liabilities

 

43,869

 

33,259

 

 

 

 

 

Other Liabilities

 

 

 

 

Deferred income taxes

 

16,630

 

17,101

Unamortized investment tax credits

 

266

 

335

Environmental liability

 

12,250

 

13,140

Regulatory liability – cost of removal

 

9,359

 

8,800

Regulatory tax liabilities

 

796

 

876

Regulatory liability – retirement plan

 

564

 

-

Long-term medical and pension reserve

 

4,817

 

4,580

Customer advances for construction

 

2,497

 

2,633

Regulatory liability – storm reserve

 

2,387

 

1,636

Total other liabilities

 

49,566

 

49,101

Total

$

192,344

$

181,234


See Notes to Consolidated Financial Statements

 

 

 

 





CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in thousands)


 

December 31,

 

 

2007

 

2006

Common Shareholders' Equity

 

 

 

 

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,182,983 shares in 2007; issued 6,166,648 shares in 2006

$

9,275 

9,250 

Paid-in capital

 

6,076 

 

6,054 

Retained earnings

 

35,797 

 

35,213 

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

 

88 

 

(103) 

Treasury stock - at cost (129,223 shares in 2007, 160,349 shares in 2006)

 

(2,290)

 

(2,842)

Total common shareholders' equity

 

48,946 

 

47,572 

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

 

9,091 

 

10,000 

10.03 % due 2018

 

5,000 

 

5,500 

9.08 % due 2022

 

8,000 

 

8,000 

4.90 % due 2031

 

14,000 

 

14,000 

                     6.85 % due 2031

 

14,990 

 

15,000 

                 Unamortized debt discount

 

(1,718)

 

(1,798)

Total long-term debt

 

49,363 

 

50,702 

Total Capitalization

$

98,909 

98,874 

See Notes to Consolidated Financial Statements

 

 

 

 





CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares Issued

 

Aggregate Par Value

 

Paid-in Capital

 

Retained Earnings

 

Accumulated Other Comprehensive (Loss)

 

Treasury Shares Cost

 

Treasury Shares

Common Shareholders’ Equity

 

 

Balances as of December 31, 2004

6,130,097 

 

$9,195 

 

$5,806 

 

$31,849 

 

$     - 

 

$(3,637)

 

205,241 

$43,213 

 

 


Net income

 

 

 

4,248 

 

 

 

4,248 

 

 

Dividends

 

 

 

(2,472)

 

 

 

(2,472)

 

 

Stock plans

22,579 

 

34 

 

192 

 

 

 

288 

 

(16,247)

514 

 

 

Balances as of December 31, 2005

6,152,676 

 

9,229 

 

5,998 

 

33,625 

 

 

(3,349)

 

188,994 

45,503 

 

 


Net income

 

 

 

4,169 

 

 

 

4,169 

 

 

Accumulated other comprehensive loss, retirement plans adjustment, net of tax

-

 

-

 

-

 

-

 

(103)

 

-

 

-

(103)

 

 

Dividends

 

 

 

(2,581)

 

 

 

(2,581)

 

 

Stock plans

13,972 

 

21 

 

56 

 

 

 

507 

 

(28,645)

584 

 

 

Balances as of December 31, 2006

6,166,648 

 

9,250 

 

6,054 

 

35,213 

 

(103)

 

(2,842)

 

160,349 

       47,572 

 

 


Net income

 

 

 

3,301 

 

 

 

3,301 

 

 

Accumulated other comprehensive income, retirement plans adjustment, net of tax

 

 

 

 

191

 

 

191

 

 

Dividends

 

 

 

(2,717)

 

 

 

       (2,717)

 

 

Stock plans

16,335 

 

25 

 

22 

 

 

 

552 

 

(31,126)

599 

 

 

Balances as of December 31, 2007

6,182,983 

 

$9,275 

 

$6,076 

 

$35,797 

 

$88

 

$(2,290)

 

129,223 

$48,946 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


See Notes to Consolidated Financial Statements



CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

 

 

Years Ended December 31,

 

 

2007

 

2006

 

2005

Cash Flows from Operating Activities:

 

 

 

 

 

 

Net income

$

3,301

$

4,169

$

4,248

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

 

 

 

 

 

 

Depreciation and amortization

 

8,286

 

7,742

 

7,266

Deferred income taxes

 

(1,198)

 

(2,003)

 

(153)

Bad debt expense

 

448

 

623

 

359

Investment tax credits

 

(69)

 

(75)

 

(81)

Other

 

886

 

805

 

751

Interest income from sale of non-utility property

 

(253)

 

(252)

 

(192)

Compensation expense from the issuance of stock

 

47

 

88

 

58

Effects of changes in:

 

 

 

 

 

 

Receivables

 

(620)

 

3,115

 

(4,513)

Unbilled receivables

 

78

 

(39)

 

367

Inventories and prepayments

 

68

 

711

 

(495)

Accounts payable and accruals

 

4,826

 

(976)

 

5,560

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

 

58

 

6,500

 

(3,171)

Area expansion program deferred costs

 

(313)

 

238

 

109

Regulatory asset and environmental liability

 

175

 

584

 

429

Other

 

(1,194)

 

(1,140)

 

(329)

     Net cash provided by operating activities

 

14,526

 

20,090

 

10,213

Cash Flows from Investing Activities:

 

 

 

 

 

 

Construction expenditures

 

(16,740)

 

(13,116)

 

(12,441)

Customer advances received for construction

 

(210)

 

361

 

454

Purchase of long-term investments

 

(80)

 

(106)

 

(75)

Proceeds received on notes receivable

 

371

 

321

 

304

      Other

 

-

 

(15)

 

-

     Net cash used in investing activities

 

(16,659)

 

(12,555)

 

(11,758)

Cash Flows from Financing Activities:

 

 

 

 

 

 

Net change in short-term borrowings

 

7,656

 

(6,092)

 

3,733

Proceeds from common stock plans

 

552

 

497

 

456

Dividends paid

 

(2,681)

 

(2,551)

 

(2,448)

     Net cash provided by (used in) financing activities

 

5,527

 

(8,146)

 

1,741

Net Increase (Decrease) in Cash

 

3,394

 

(611)

 

196

Cash at Beginning of Year

 

84

 

695

 

499

Cash at End of Year

$

3,478

$

84

$

695

Supplemental Cash Flow Information

 

 

 

 

 

 

Cash was paid during the years as follows:

 

 

 

 

 

 

     Interest

$

4,375

$

4,777

$

4,469

     Income taxes

$

1,984

$

3,298

$

2,698



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 Florida Public Service Commission (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 Federal Energy Regulatory Commission (FERC).  The Northeast Florida division is supplied most of its electric power by a municipality which is exempt from FERC and FPSC regulation.  The Company also distributes propane gas through a non-regulated subsidiary.


B. Basis of Presentation

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


C. Use of Estimates

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


D. Reclassifications

Certain amounts in the prior years' financial statements have been reclassified to conform to the 2007 presentation.


E. Regulation

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

 


Summary of Regulatory Assets and Liabilities

(Dollars in thousands)

 

2007 

2006 

Assets

 

 

Deferred development costs  (1)

$  4,265 

$  3,952 

Unamortized fuel related regulatory costs (5)

36 

48 

Environmental assets (2)

7,653 

8,271 

Storm Reserve assets (3)

283 

Deferred retirement plan costs (4)

587 

Unamortized Rate Case expense (7)

535 

368 

Under-recovery of fuel costs (6)

862 

Unamortized piping and conversion costs   (1)

1,379 

1,521 

Unamortized loss on reacquired debt   (1)

190 

209 

Total Regulatory Assets

            $14,058

$16,101 

  

 

 

Liabilities

 

 

Tax liabilities (8)

$     796 

$     876 

Cost of removal (9)

9,359 

8,800 

Deferred retirement plan costs  (4)

564 

Storm reserve liabilities(3)

2,387 

1,636 

Over-recovery of fuel costs (6)

2,761 

3,656 

Over-recovery of conservation (6)

446 

355 

Over-earnings liability (3)

26 

722 

Total Regulatory Liabilities

            $16,339

$16,045 


(1)

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

(2)

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

(3)

The Commission ordered disposition of our 2005 over-earnings to eliminate the related regulatory asset-storm reserve and the storm surcharge collected from customers in our natural gas operations. The remaining over-earnings was used to fund a storm reserve for future storm costs in our natural gas division.  Our natural gas storm reserve is approximately $613,000 as of December 31, 2007 as a result of this order.

(4)

The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 at December 31, 2006 resulted in a regulatory asset for the portion of the loss of $587,000 and at December 31, 2007 resulted in a regulatory liability for $564,000.

(5)

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

(6)

The Company has certain costs that are passed directly through to customers for recovery including fuel and conservation costs. There are amounts related to these expenses that are either over or under-recovered in a calendar year. These over-recoveries will be returned to customers and under-recoveries will be collected from customers in the following year, but both are deferred in the current period.

(7)

The Company has costs associated with preparing and filing a rate proceeding before the FPSC. These costs are amortized over a four or five year period. This represents the unamortized portion of these costs. The Company has incurred additional rate case costs associated with the electric filing expected to be finalized in 2008. The additional costs are expected to be amortized over a four year period beginning mid 2008.

(8)

The Company has deferred tax liabilities associated with property. The Company uses a FPSC-approved method to amortize these liabilities.

(9)

The Company has a liability for the estimated future costs to remove or retire existing fixed assets.

 


 

The base revenue rates for regulated segments are determined by the FPSC and remain constant until a request for an increase is filed and approved by the FPSC or the FPSC orders the Company to reduce their rates.  For the Company to recover increased costs from the effects of inflation and construction expenditures for regulated segments, a request for an increase in base revenues would be required. Separate filings would be required for the electric and natural gas segments.  The Company is currently seeking rate relief in their electric segment, and approval, if any, is expected in the second quarter of 2008.


At December 31, 2007, all of our regulatory assets and all of our regulatory liabilities are reflected or are expected to be reflected in rates charged to customers. 


Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that restricts our ability to establish prices to recover specific costs, and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation.  We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate.  Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, we believe that our regulatory assets are probable of recovery.


F. Derivatives

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

 

G. Revenue Recognition

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


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


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


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


Interim rate relief for partial recovery of the increased expenditures was approved by the Commission on October 23, 2007. Interim rates which should produce additional annual revenues of approximately $800,000 went into effect for meter readings on and after November 22, 2007. The permanent rates may differ from the interim rates, and the interim rates are collected subject to refund with interest.


H.

Taxes Collected from Customers and Remitted to Governmental Authorities

The Company remits to governmental authorities various taxes collected from customers throughout the year including gross receipts and franchise taxes. These taxes are pass through revenues and expenses and do not impact the Company’s results of operations. The amount of gross receipts and franchise taxes for the year ending December 31, 2007 and 2006 was $7.1 million and $6.9 million, respectively.


I. Allowance for Doubtful Accounts

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


Allowance for Doubtful Accounts

(Dollars in thousands)

 

Balance at Beginning of Year

Write-offs

Provisions to Bad Debt Expense

Balance at End of Year

2005

$ 269

356

359

$ 272

2006

$ 272

466

623

$ 429

2007

$ 429

551

448

$ 326

 

      J. Utility Plant and Depreciation

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


Utility Plant

 

(Dollars in thousands)

 

Plant Classification

Annual Composite Depreciation Rate

2007 

2006 

Land

 

$      4,675 

$      1,130 

Buildings

2.0% to 4.9%

7,085 

6,991 

Distribution

2.0% to 7.5%

167,252 

158,010 

Transmission

2.2% to 3.8%

6,894 

6,878 

Equipment

2.2% to 20.0%

13,307 

12,700 

Furniture and Fixtures

4.8% to 20.0%

417 

392 

Work-in-Progress

 

2,754 

2,867 

 

 

$ 202,384 

$ 188,968 


Depreciation for the Company’s regulated segments is computed using the composite straight-line method at rates prescribed by the FPSC for financial accounting purposes.  Propane gas depreciation is computed using a composite straight-line method at an average rate based on estimated average life of approximately 20-30 years.  Such rates are based on estimated service lives of the various classes of property.  Depreciation provisions on average depreciable property approximate 3.8% in 2007, 3.9% in 2006 and 3.9% in 2005. Depreciation expense was $6.7 million, $6.2 million and $5.7 million for 2007, 2006 and 2005, respectively.


K. Impact of Recent Accounting Standards


Financial Accounting Standard No. 157

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements”.  This Statement clarifies fair value as the market value received to sell an asset or paid to transfer a liability, that is, the exit value, and applies to any assets or liabilities that require recurring determination of fair value.  The measurement includes any applicable risk factors and does not include any adjustment for volume.  On February 12, 2008, the FASB issued proposed FASB Staff Position No. FAS No. 157-2, “Effective Date of FASB Statement No. 157” which defers the effective date for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (that is, at least annually) to fiscal years beginning after November 15, 2008. The Company expects to adopt SFAS No. 157 effective January 1, 2009. The Company is still evaluating the impact adoption of this Statement will have on our financial condition or results of operation.


Financial Accounting Standard No. 159

In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”.  This Statement permits measurement at fair value of certain firm commitments, nonfinancial insurance contracts and warranties, host financial instruments and recognized financial assets and liabilities, excluding consolidating investments in subsidiaries, consolidating variable interest entities, various forms of deferred compensation agreements, leases, depository institution deposit liabilities and financial instruments included in shareholders’ equity.  This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company does not expect to adopt SFAS No. 159.


Financial Accounting Standard No. 160

In December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”.  This standard requires noncontrolling ownership interests be disclosed separately in equity, separate disclosure of income contributable to each party, changes in controlling interests be reported consistently, and deconsolidation be measured at fair value. As the company does not currently have any noncontrolling interests this standard will not have an impact on our financial condition or results of operations until the Company acquires a noncontrolling interest.

 

Financial Accounting Standard No. 141R

In December 2007, the FASB issued a revision to Statement No. 141, “Business Combinations”. This statement is effective prospectively for business combinations occurring on or after January 1, 2009 for our company.  This revision broadens the scope of a business combination to include transactions in which no consideration has been exchanged, sets the acquisition date as the date control is obtained, replaces the cost allocation method with fair value method to assign values to assets and liabilities assumed, requires restructuring costs to be recorded separate of the business combination, and does not permit deferral of contractual contingencies at acquisition date.  As this revision is adopted prospectively and all qualifying future business combinations would be evaluated under the new provisions, the effects on our results of operations will depend on the nature and size of any future acquisitions.

 

L. Earnings Per Share

The Company includes earnings per common share (basic and diluted) on the consolidated statements of income. The Company does not have dilutive or anti-dilutive shares.


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 with indefinite lives to fair value. The impairment tests performed in 2006 and 2007 showed no impairment for either reporting segment.


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


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


Intangible Assets

(Dollars in thousands)

 

 

2007 

2006 

Customer distribution rights

(Indefinite life)

$ 1,900 

$ 1,900 

Customer relationships

(Indefinite life)

900 

900 

Software

(Five to nine year life)

3,499 

3,122 

Accumulated amortization

(1,869)

(1,517)

Total intangible assets, net of amortization

$4,430 

$ 4,405 


The 2007 amortization expense of computer software is approximately $352,000. 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.  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.


In 2007, there were no estimated natural gas over-earnings.


The Company recorded estimated 2006 over-earnings for regulated natural gas operations of $25,000. Interest accrued on this estimated over-earnings as of December 31, 2007 is $1,300. This liability is included in the over-earnings liability on the Company’s consolidated balance sheet of December 31, 2007. The calculations supporting these liabilities are complex and involve a variety of projections and estimates before the ultimate settlement of such obligations. Estimates may be revised as expectations change and factors become known and determinable.

 

The 2006 over-earnings liability is based on the Company’s best estimate, but the amount could change upon the FPSC finalization expected in 2008. The FPSC determines the disposition of over-earnings with alternatives that include refunding to customers, increasing storm damage or environmental reserves or reducing any depreciation reserve deficiency.


On August 14, 2007 the Commission finalized the disposition of 2005 over-earnings for the natural gas segment. Total over-earnings was determined to be $666,000, plus interest of $76,000.


The Commission ordered disposition of 2005 over-earnings to eliminate the related regulatory asset-storm reserve in natural gas operations and the storm surcharge collected from customers. The remaining over-earnings was used to fund a storm reserve for any future storm costs.  


2005 Natural Gas Over-Earnings Summary

 (Dollars in thousands)

 

December 31, 2007

 

Before Application of PSC Order

2007 Adjustment

After Application of PSC Order

Current Assets:

 

 

 

Other regulatory assets-storm reserve current

$             116

$         (116)

$                0

 

 

 

 

Assets:

 

 

 

Other regulatory assets-storm reserve

13

(13)

0

 

 

 

 

Capitalization and Liabilities:

 

 

 

Over-earnings liability

768

(742)

26

Regulatory liability -storm reserve

1,774

613

2,387

 

 

 

 

Revenues:

 

 

 

Natural Gas Revenue

64,866

(16)

64,850

 

 

 

 

Other Income and (Deductions):

 

 

 

Interest expense on customer deposits and other

(659)

(76)

(735)



4.  Storm Reserves

As of December 31, 2007, the Company had a storm reserve of approximately $1.8 million for the electric segment and approximately $613,000 for the natural gas segment. The Company does not have a storm reserve for the propane gas segment.


As noted above, in the August 2007 the Commission ordered disposition of 2005 over-earnings to eliminate the related regulatory asset – storm reserve in natural gas operations and the storm surcharge collected from customers. The remaining over-earnings was used to fund a storm reserve for any future storm costs.


5.  Income Taxes

Financial Accounting Standard Board Interpretation No. 48

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

 

At January 1, 2007, we performed an analysis of tax positions taken and expected to be taken on the tax returns and assessed the technical merits of each tax position by relying on legislation, statutes, common legislative intent, regulations, rulings and case law and determined that the Company has no material uncertain tax positions.  


In February of 2007, the IRS selected our 2003 and 2004 tax years for examination. As of December 31, 2007, the IRS examination was not complete.  We performed an assessment of our uncertain tax positions as of December 31, 2007, and recognized a FIN 48 liability for various tax positions relating solely to the timing of various tax deductions.  A disallowance of the shorter deductibility period for these tax positions would not affect the annual effective income tax rate.  These tax positions relate to the 2004 through 2007 tax years.  The effects of these tax positions are disclosed in the reconciliation below.

 

Changes during the year in unrecognized tax benefits were as follows:

(Dollars in thousands)

Balance at January 1, 2007

$        -

     Additions based on tax positions related to the current year

     (23)

     Additions for tax positions of prior years

  291

     Reductions for tax positions of prior years

 -

     Settlements

      -

Balance at December 31, 2007

$    268


In February 2008, the IRS submitted its Notice of Proposed Adjustment to us.  We have reviewed and expect to agree to the IRS proposed audit adjustments in March 2008.  


It is reasonably possible that a liability associated with uncertain tax positions may arise within the next twelve months.  These changes may be the result of the ongoing IRS audit, the expiration of statutes of limitations or from other developments. At this time an estimate of reasonably possible outcomes cannot be made.


We are subject to taxation in the United States and the State of Florida.  Our tax years from 2004 through 2007 are subject to examination by the tax authorities.


The Company’s policy regarding interest and penalties related to income tax matters is to recognize such items separately and not as components of income tax expense.  For the year ended December 31, 2007 we have recognized $44,000 in interest expense and accrued interest and no penalty expense related to income tax matters.


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. Provision for Income Taxes

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


(Dollars in thousands)

 

 

 

2007 

 

2006 

 

Current payable

 

 

 

 

 

  Federal

$

2,518 

3,652 

 

  State

 

446 

 

664 

 

    Current

 

2,964 

 

4,316 

 

Deferred

 

 

 

 

 

  Federal

 

(1,028)

 

(1,723)

 

  State

 

(170)

 

(280)

 

     Deferred – net

 

(1,198)

 

(2,003)

 

 

 

 

 

 

 

Investment tax credit

 

(69)

 

(75)

 

 

 

 

 

 

 

Total income taxes

$

1,697 

2,238 

 


B. Effective Tax Rate Reconciliation

The difference between the effective income tax rate and the statutory federal income tax rate applied to pretax income is as follows:


 (Dollars in thousands)

 

Years ended December 31,

 

 

2007 

 

2006 

 

2005 

Federal income tax at statutory rate (34%)

1,699 

2,178 

2,222 

State income tax, net of federal benefit

 

181 

 

233 

 

237 

Investment tax credit

 

(69)

 

(75)

 

(81)

Tax exempt interest

 

(85)

 

(85)

 

(71)

Other

 

(29)

 

(13)

 

(20)

Total provision for income taxes

1,697 

2,238 

2,287 


       C. Deferred Income Taxes

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



(Dollars in thousands)

Years ended December 31,

Deferred tax assets:

2007 

 

2006 

   Environmental liability

$    2,249 

 

 $        2,063 

   Self insurance liability

763 

 

774 

   Storm reserve liability

898 

 

509 

   Vacation payable

384 

 

357 

   Other deferred credits

 

15 

   Allowance for doubtful accounts

123 

 

162 

   Amortizable customer based intangibles

670 

 

   General liability

82 

 

68 

   Rate refund liability

10 

 

271 

   Pension liability

1,086 

 

789 

   Under/over-recovery of conservation costs

167 

 

 134 

   Other liabilities

47 

 

37 


 

Total deferred tax assets

    6,479 

 

       5,179 


Deferred tax liabilities:

 

 

 

   Utility plant related

   20,677 

 

      20,274 

   Deductible intangibles

781 

 

696 

   Under-recovery of fuel costs

406 

 

643 

   Deferred rate case expense

201 

 

138 

   Loss on reacquired debt

71 

 

79 

   Other

24 

 

32 

Total deferred tax liabilities

   22,160 

 

    21,862 

 

 

 

 

Net deferred income taxes liabilities

$   15,681 

 

$   16,683 

 

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


(Dollars in thousands)

2007 

 

2006 

 

 

 

 

Deferred income tax asset (liability) – current

$          949

 

$           (579)

Deferred income tax liability – long term

(16,630)

 

(16,104)

Net deferred income tax liabilities

$  (15,681)

 

$     (16,683)


6.  Capitalization


A. Common Shares Reserved

The Company has 3,817,017 authorized but unissued shares and 129,223 treasury shares as of December 31, 2007. The Company has reserved the following common shares for issuance as of December 31, 2007:


Dividend Reinvestment Plan

37,736 

Employee Stock Purchase Plan

24,059 

Board Compensation Plan

17,564 

 

 


B. 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, 2007. The preferred stock is included in stockholders’ equity on the balance sheet.


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


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


C. 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, 2007, approximately $9.6 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. As of December 31, 2007 the Company was not in violation of these covenants.

 

D. Employee Stock Purchase Plan

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


E. Dividend Reinvestment Plan

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


7.  Long-term Debt

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


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


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


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


Long-term debt on the balance sheet has been reduced for unamortized debt discount. The unamortized debt discount at December 31 included in long-term debt on the balance sheet is $1.7 million in 2007 and $1.8 million in 2006.


Annual Maturities of Long-Term Debt

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

Total

2008

2009

2010

2011

2012

Thereafter

 

 

 

 

 

 

 

 

 

Long-term Debt

$52,490

$1,409

$1,409

$1,409

$1,409

$1,409

$ 45,445


8.  Line of Credit

In 2004, FPU entered into an amended and restated loan agreement that allows the Company to increase the line of credit upon 30 days notice by the Company to a maximum of $20 million.  In 2006 the agreement was renewed with an expiration date of July 1, 2008. We have not exercised our option to increase the line of credit limit which is currently at $12 million with an outstanding balance of $11.1 million.   The Company reserves $1 million of the line of credit to cover expenses for any major storm repairs in its electric segment.  An additional $250,000 of the line of credit is reserved for a ‘letter of credit’ insuring our propane facilities. In March 2008, we amended our line of credit to allow us, upon 30 days notice, to increase our maximum credit line to $26 million. The new agreement expires July 1, 2010. The amendment also reduces the interest rate paid on borrowings by .10% or 10 basis points. The new interest rate terms, if effective for 2007, would have reduced our overall average interest rate for 2007 to approximately 5.7% from 5.8% as of December 31, 2007.

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


Year

Rate

2007

5.8%

2006

6.2%

2005

5.3%


9.  Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for investments held in escrow for environmental costs, notes payable, taxes accrued and other accrued liabilities approximate fair value.  The fair value of long-term debt excluding the unamortized debt discount is estimated by discounting the future cash flows of each issuance at rates currently offered to the Company for similar debt instruments of comparable maturities. The indentures governing our two first mortgage bond series outstanding contain "make-whole" provisions (pre-payment penalties that charge for lost interest). The values at December 31 are shown below.


 

2007

2006


(Dollars in thousands)

Carrying

Amounts

Approximate Fair Value

Carrying

Amounts

Approximate Fair Value

Long-term debt

$ 52,490

$60,000

$52,500

$ 63,000


10.  Contingencies

 

Environmental

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

(Dollars in thousands)

Site

Range From

Range To

West Palm Beach

$      4,926

$   18,152

Sanford

727

727

Pensacola and Key West

123

123

Total

$      5,776

 $   19,002

 


The Company currently has $13.6 million recorded as our best estimate of the environmental liability. The FPSC approved up to $14 million for total recovery from insurance and rates based on the original 2005 projections as a basis for rate recovery. The Company has recovered a total of $6 million from insurance and rate recovery, net of costs incurred to date.  The remaining balance of $7.6 million is recorded as a regulatory asset.  On October 18, 2004 the FPSC approved recovery of $9.1 million for environmental liabilities.  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 may continue for another 10 years.


West Palm Beach Site

The Company is currently evaluating remedial options to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by it in West Palm Beach, Florida upon which the Company previously operated a gasification plant. The Company entered into a Consent Order with the FDEP effective April 8, 1991, that requires the Company to delineate the extent of soil and groundwater impacts associated with the prior operation of the gasification plant and to remediate such soil and groundwater impacts, if necessary. The Company completed field investigations for the contamination assessment task in October 2006.  Thereafter, The Company retained an engineering consultant, The RETEC Group, Inc. (RETEC), to perform a feasibility study to evaluate appropriate remedies for the site to respond to the reported soil and groundwater impacts.  On November 30, 2006, RETEC transmitted a feasibility study to the Company and FDEP.  The feasibility study evaluated a wide range of remedial alternatives. The total costs for the remedies evaluated in the feasibility study ranged from a low of $2.8 million to a high of $54.6 million.  Based on the likely acceptability of proven remedial technologies described in the feasibility study and implemented at similar sites, consulting/remediation costs are projected to range from $4.6 million to $17.9 million. This range of costs covers such remedies as in situ solidification for the deeper impacts, excavation of surficial soils, installation of a barrier wall with a permeable biotreatment zone, or some combination of these remedies.  


By letter dated May 7, 2007, FDEP provided its comments to the feasibility study, the substance of which was discussed at a meeting between the Company and FDEP on September 14, 2007.  A response to the comments was submitted by the Company to FDEP on October 31, 2007.  We are currently awaiting FDEP's comments to the response. 

 

Based on the information provided in the feasibility study, remaining legal fees are currently projected to be approximately $295,000. Consulting and remediation costs are projected to range from $4.6 million to $17.9 million. Thus, the Company's total probable legal and cleanup costs for the West Palm Beach site are currently projected to range from $4.9 million to $18.2 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 (collectively, the Group) and the EPA. This AOC obligated the Group to implement a Remedial Investigation/Feasibility Study (RI/FS) and to pay EPA's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998 (WFS Participation Agreement). Work under the RI/FS AOC and RI/FS Participation Agreement is now complete and the Company has no further obligations under either agreement.

 

In late September 2006, the EPA sent a Special Notice Letter to the Company, notifying it, and the other responsible parties at the site (Florida Power Corporation, Florida Power & Light Company, Atlanta Gas Light Company, and the City of Sanford, Florida, collectively with FPUC, "the Sanford Group"), of EPA's selection of a final remedy for OU1 (soils), OU2 (groundwater), and OU3 (sediments) for the site.  The total estimated remediation costs for the Sanford gasification plant site are now projected to be $12.9 million. The Sanford Group was further advised that the EPA was willing to negotiate a consent decree with the Sanford Group to provide for the implementation of the final remedy approved by the EPA for the site. 

 

In January 2007, the Company and other members of the Sanford Group signed a Third Participation Agreement, which provides for funding the final remedy approved by the EPA for the site.  The Company's share of remediation costs under the Third Participation Agreement is set at a maximum of $650,000, providing the total cost of the final remedy does not exceed $13 million.  At present, it is not anticipated that the total cost will exceed $13 million.  If it does, the Sanford Group members have agreed to negotiate in good faith at such time that it appears that the total cost will exceed $13 million for the allocation of the additional cost.  The Company has advised the other members of the Sanford Group that the Company is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by the Company in the Third Participation Agreement.


On June 26, 2007, the Sanford Group transmitted to the EPA a consent decree signed by all Group Members, providing for the implementation by the Sanford Group of the remedy selected by the EPA for the site.  The consent decree is currently being circulated within the EPA and the United States Department of Justice for execution by those parties.  Thereafter, the consent decree will be lodged with the federal court in Orlando, Florida.  Following a public comment period, it is anticipated that the federal court will enter the consent decree.  The Sanford Group will then be obligated to implement the remedy approved by the EPA for the site. 


Remaining legal fees and costs are currently projected to be approximately $77,000. The Company's obligation under the Third Participation Agreement is $650,000. Thus, the Company's total probable legal and cleanup costs for the Sanford site are currently projected to be approximately $727,000. 


Pensacola Site

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

 

Consulting and remediation costs are projected to be $26,000 and legal fees are projected to be $4,000, for total probable costs for the Pensacola site of $30,000.


Key West Site

From 1927-1938, we owned and operated a gasification plant in Key West, Florida. The plant discontinued operations in the late 1940s; the property on which the plant was located is currently used for a propane gas distribution business. In March 1993, a Preliminary Contamination Assessment Report (PCAR) was prepared by a consultant jointly retained by the current site owner and the Company and was delivered to FDEP. The PCAR reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, FDEP notified us that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." FDEP then referred the matter to its Marathon office for consideration of whether additional work would be required by FDEP's district office under Florida law.


Consulting and remediation costs are projected to be $83,000 and legal fees are projected to be $10,000, for total probable costs for the Key West site of $93,000.


11.  Commitments


A. General

To ensure a reliable supply of electric and natural gas at competitive prices, the Company has entered into long-term purchase and transportation contracts with various suppliers and producers, which expire at various dates through 2023.  At December 31, 2007, 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 $41.9 million during 2008 related to gas purchase agreements.  Substantially all costs incurred under the electric and gas purchase agreements are currently recoverable from customers through fuel adjustment clause mechanisms.


12.  Employee Benefit Plans


The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 resulting in an additional liability for retirement plans, pension plan and retirees’ medical plan have been recorded.


A. Pension Plan

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

 

Our Company adopted the recognition provisions of Statement 158, as required, at December 31, 2006 and used December 31 as the measurement date to measure the assets and obligations of its retirement plans. This resulted in an additional liability for retirement plans. The tax on the non-regulated portion of the liability has been recorded as a deferred income tax asset/liability. As an offset, the regulatory portion of this liability has been deferred as a regulatory asset/liability to be recovered in future rate proceedings and the remaining income/loss has been included in other accumulated comprehensive income/loss.


The fair value of our retirement plan assets and obligations are subject to change based on market fluctuations.


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

 

The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the 3-year period ending December 31, 2007 and a statement of the funded status as of December 31, of all three years:


 

Benefit Obligations and Funded Status

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Change in Projected Benefit Obligation

 

 

 

 

 

 

(a)

Projected Benefit Obligation at the Beginning of the Year

$38,650,888

 

$36,349,925

 

$34,926,383

 

(b)

Service Cost

1,053,824

 

1,225,495

 

1,195,723

 

(c)

Interest Cost

2,293,540

 

2,160,719

 

2,000,099

 

(d)

Actuarial (Gain) or Loss

(909,856)

 

541,865

 

(842,777)

 

(e)

Benefits Paid

(1,568,572)

 

(1,529,258)

 

(1,514,341)

 

(f)

Change in Plan Provisions

-

 

-

 

-

 

(g)

Curtailment

-

 

(97,858)

 

584,838

 

(h)

Projected Benefit Obligation at the End of the Year

$39,519,824

 

$38,650,888

 

$36,349,925

 

(i)

Accumulated Benefit Obligation (ABO) at the End of the Year

$34,139,719

 

$33,693,860

 

$31,966,513

(2)

Change in Plan Assets

 

 

 

 

 

 

(a)

Fair Value of Plan Assets at the Beginning of the Year

$35,635,214

 

$32,936,666

 

$32,385,214

 

(b)

Actual Return on Plan Assets

1,923,674

 

3,977,806

 

2,065,793

 

(c)

Benefits Paid

(1,568,572)

 

(1,529,258)

 

(1,514,341)

 

(d)

Employer Contributions

250,000

 

250,000

 

-

 

(e)

Fair Value of Assets at the End of the Year

$36,240,316

 

$35,635,214

 

$32,936,666

 

 

 

 

 

 

 

(3)

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

$(3,279,508)

 

$(3,015,674)

 

$(3,413,259)

(4)


Amounts Recognized in the Statement of Financial Position

Before Applying FAS 158

 

 

 

 

 

(a)

Prepaid (Accrued) Benefit Cost

$(3,466,255)

 

$(2,070,740)

 

$(721,333)

 

(b)

Net Asset (liability)

$(3,466,255)

 

$(2,070,740)

 

$(721,333)

 

(c)

Charge to Accumulated Other Comprehensive Income:

-

 

-

 

-

(5)

Adjustments Caused by Applying FAS 158

 

(a)

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

$186,747

 

$(944,934)

 

N/A

 

(b)

Increase in Charge to Accumulated Other Comprehensive Income:

(29,768)

 

207,885

 

N/A

 

(c)

Increase in Charge to Regulatory Asset –retirement plans

(156,979)

 

737,049

 

N/A

 

(d)

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

$             -

 

$              -

 

N/A

(6)


Amount Recognized in Statement of Financial Position

After applying FAS 158

 

 

 

 

 

(a)

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

$(3,279,508)

 

$(3,015,674)

 

$(721,333)

 

(b)

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


$(29,768)

 


$207,885

 


-

 

(c)

Regulatory Asset-Retirement Plans (5) (c)

$(156,979)

 

$737,049

 

-

(7)


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

After applying FAS 158

 

 

 

 

 

(a)

Noncurrent Assets

-

 

-

 

N/A

 

(b)

(Current Liabilities)

-

 

-

 

N/A

 

(c)

(Noncurrent Liabilities)

$(3,279,508)

 

$(3,015,674)

 

N/A






 

(d)

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

$(3,279,508)

 

$(3,015,674)

 

N/A

(8)


Amount Recognized in Accumulated Other Comprehensive Income

And Regulatory Asset –Retirement Plans After applying FAS 158

 

 

 

 

 

(a)

Transition Obligation (Asset)

 

 

N/A 

 

(b)

Prior Service Cost (Credit)

$3,255,374

 

$3,992,489

 

N/A

 

(c)

Net (Gain)

(3,442,121)

 

(3,047,555)

 

N/A

 

(d)

Total

$(186,747)

 

$944,934

 

N/A

(9)


Weighted Average Assumption at End of Year

 

 

 

 

 

(a)

Discount Rate

6.65%

 

6.00%

 

5.90% 

 

(b)

Rate of Compensation Increase

3.90%

 

3.25%

 

3.15% 

 

(c)

Mortality

RP-2000

 

GAM 83

 

GAM 83


The following table provides the components of net periodic benefit cost for the plans for fiscal years 2007, 2006 and 2005:


Net Periodic Pension Costs

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Service Cost

$1,053,824

 

$1,225,495

 

$1,195,723

(2)

Interest Cost

2,293,540

 

2,160,719

 

2,000,099

(3)

Expected Return on Plan Assets

(2,438,964)

 

(2,426,064)

 

(2,485,985)

(4)

Amortization of Transition Obligation/(Asset)

-

 

-

 

-

(5)

Amortization of Prior Service Cost

737,115

 

737,115

 

737,115

(6)

Amortization of Net (Gain)

-

 

-

 

-

(7)

Total FAS 87 Net Periodic Pension Cost

$1,645,515

 

$1,697,265

 

$1,446,952

(8)

FAS 88 Charges / (Credits)

 

 

 

 

 

 

(a)

Curtailment

-

 

(97,858)

 

-

(9)

Total Net Periodic Pension Cost and Comprehensive Income

$1,645,515

 

$1,599,407

 

$1,446,952

(10)

Weighted Average Assumptions

 

 

 

 

 

 

(a)

Discount Rate at Beginning of the Period

6.00%

 

5.90%

 

5.75%

 

(b)

Expected Return on Plan Assets

8.50%

 

8.50%

 

8.50%

 

(c)

Rate of Compensation Increase

3.25%

 

3.15%

 

3.00%



Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2008

2007

2006

2005

(1)

Plan Assets

 

 

 

 

 

(a)

Equity Securities

40% - 75%

64%

68%

67%

 

(b)

Debt Securities

25% - 50%

36%

30%

32%

 

(c)

Real Estate

0% - 0%

0%

0%

0%

 

(d)

Other

  0% - 15%

0%

2%

1%

 

(e)

Total

 

100%

100%

100%


Expected Return on Plan Assets

The expected rate of return on plan assets is 8.5%.  The Company expects 8.5% to fall within the 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, 2008

 

(a)

Expected Employer Contributions

 

$250,000 

 

(b)

Expected Employee Contributions

 

-

(2)

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

 

 

(a)

2008

 

 

 

 $1,854,039

 

(b)

2009

 

 

 

 $2,012,880

 

(c)

2010

 

 

 

 $2,141,170

 

(d)

2011

 

 

 

 $2,237,970

 

(e)

2012

 

 

 

 $2,370,069

 

(f)

2013 – 2017

 

 

 $14,320,239

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/08

-



Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

2005

(1)  

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

 $31,290,939

 

 $29,290,131

 

 $30,016,761

(2)


  

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

$ 0

 

$ 0

 

$ 0

(3)  

Alternative Amortization Methods Used to Amortize

 

 

 

 

 

 

(a)

Prior Service Cost

Straight Line

 

Straight Line

 

Straight Line

 

(b)

Unrecognized Net (Gain) or Loss

Straight Line

 

Straight Line

 

Straight Line

(4)

Average Future Service

10.56

 

10.80

 

10.95

(5)


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

None

 

None

 

None

(6)

Description of Special or Contractual Termination Benefits Recognized During the Period

N/A

 

N/A

 

N/A

(7)

Cost of Benefits Described in (6)

N/A

 

N/A

 

N/A

 

(8)

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

N/A

 

N/A

 

N/A

(9)

Measurement Date Used

December 31, 2007

 

December 31, 2006

 

December 31, 2005

 

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, 2007:


Benefit Obligations and Funded Status

 

 

 

Fiscal Year Ending

 

 

 

12/31/2007

 

12/31/2006

 

12/31/2005

(1)

Change in Accumulated Postretirement Benefit Obligation (ABO)

 

 

 

 

 

 

(a)

Accumulated Postretirement Benefit Obligation at the Beginning of the Year

$1,865,353

 

$2,343,583

 

$1,925,254

 

(b)

Service Cost

54,603

 

59,982

 

100,054

 

(c)

Interest Cost

95,348

 

105,483

 

127,312

 

(d)

Actuarial (Gain) or Loss

(329,969)

 

(568,755)

 

282,812

 

(e)

Benefits Paid

(96,975)

 

(117,459)

 

(135,166)

 

(f)

Change in Plan Provisions

-

 

-

 

-

 

(g)

Plan Participant's Contributions

33,193

 

42,519

 

43,317

 

(h)

Accumulated Postretirement Benefit Obligation at the End of the Year

$1,621,553

 

$1,865,353

 

$2,343,583

(2)

Change in Plan Assets

 

 

 

 

 

 

(a)

Fair Value of Plan Assets at the Beginning of the Year

$             -

 

$              -

 

$              -

 

(b)

Benefits Paid

(96,975)

 

(117,459)

 

(135,166)

 

(c)

Employer Contributions

63,782

 

74,940

 

91,849

 

(d)

Plan Participant's Contributions

33,193

 

42,519

 

43,317

 

(e)

Fair Value of Assets at the End of the Year

            -

 

$              -

 

$              -


(3)

Net Amount Recognized

 

 

 

 

 

 

(a)

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

$(1,621,553)

 

$(1,865,353)

 

$(2,343,583)


(4)

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

 

 

 

 

 

 

(a)

Prepaid (Accrued) Benefit Cost

$(2,138,886)

 

$(2,057,833)

 

$(1,942,393)

 

(b)

(Additional Liability due to an Unfunded ABO)

-

 

-

 

-

 

(c)

Intangible Asset

-

 

-

 

-

 

(d)

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

$(2,138,886)

 

$(2,057,833)

 

$(1,942,393)

 

(e)

Charged to Accumulated Other Comprehensive Income:

-

 

-

 

-


(5)

Adjustments Caused by Applying FAS 158

 

 

 

 

 

 

(a)

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

$517,333

 

$192,480

 

N/A

 

(b)

Increase in charge to Accumulated Other Comprehensive Income:

(110,565)

 

(42,346)

 

N/A

 

(c)

Increase in charge to Regulatory Asset-retirement plans

(406,768)

 

(150,134)

 

N/A

 

(d)

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

$             -

 

$             -

 

N/A


 


(6)

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

 

 

 

 

 

 

(a)

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

$(1,621,553)

 

$(1,865,353)

 

$(1,942,393)

 

(b)

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

(110,565)

 

(42,346)

 

-

 

(c)

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

(406,768)

 

(150,134)

 

-


(7)

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

 

 

 

 

 

 

(a)

Noncurrent Assets

$                 -

 

$                  -

 

N/A

 

(b)

(Current Liabilities)

(88,176)

 

(150,589)

 

N/A

 

(c)

(Noncurrent Liabilities)

(1,533,377)

 

(1,714,764)

 

N/A

 

(d)

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

$(1,621,553)

 

$(1,865,353)

 

N/A


(8)

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

 

 

 

 

 

 

(a)

Transition Obligation (Asset)

$214,470

 

$257,366

 

N/A

 

(b)

Prior Service Cost (Credit)

-

 

-

 

N/A

 

(c)

Net (Gain) or Loss

(731,803)

 

(449,846)

 

N/A

 

(d)

Total

$(517,333)

 

$(192,480)

 

N/A


(9)

Weighted Average Assumptions at the End of the Year

 

 

 

 

 

 

(a)

Discount Rate

6.45%

 

6.00%

 

5.90%

 

(b)

Rate of Compensation Increase

N/A

 

N/A

 

N/A

 

(c)

Mortality

RP-2000

 

GAM 83

 

GAM 83


(10)

Assumed Health Care Cost Trend Rates

 

 

 

 

 

 

(a)

Health Care Cost Trend Rate Assumed for Next Year

10.50%

 

11.50%

 

9.00%

 

(b)

Ultimate Rate

5.00%

 

5.00%

 

5.00%

 

(c)

Year that the Ultimate Rate is Reached

2014

 

2014

 

2010



Net Periodic Postretirement Benefit Cost

 

 

 

Years ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Service Cost

 $54,603

 

 $59,982 

 

 $100,054 

(2)

Interest Cost

 95,348

 

 105,483 

 

 127,312 

(3)

Amortization of Transition Obligation/(Asset)

 42,896

 

 42,896 

 

 42,896 

(4)

Amortization of Prior Service Cost

-

 

-

 

-

(5)

Amortization of Net (Gain) or Loss

 (48,012)

 

 (17,981) 

 

             -

(6)

Total Net Periodic Benefit Cost

 $144,835

 

 $190,380 

 

 $270,262 

(7)

Weighted Average Assumptions

 

 

 

 

 

 

(a)

Discount Rate

6.00% 

 

5.90% 

 

5.75% 

 

(b)

Expected Return on Plan Assets

N/A 

 

N/A 

 

N/A 

 

(c)

Rate of Compensation Increase

N/A 

 

N/A 

 

N/A 

(8)

Assumed Health Care Cost Trend Rates

 

 

 

 

 

 

(a)

Health Care Cost Trend Rate Assumed for

11.50% 

 

12.50% 

 

10.00% 

 

 

 

Current Year

 

 

 

 

 

 

(b)

Ultimate Rate

5.00% 

 

5.00% 

 

5.00% 

 

(c)

Year that the Ultimate Rate is Reached

2014 

 

2014 

 

2010 

Expected Amortizations

 

 

 

Years ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Expected Amortization of Transition Obligation (Asset)

$42,896

 

$42,896

 

N/A

(2)

Expected Amortization of Prior Service Cost (Credit)

-

 

-

 

N/A

(3)

Expected Amortization of Net Loss (Gain)

(51,238)

 

(48,012)

 

N/A

(9)

Impact of One-Percentage-Point Change in

 

 

 

 

 

 

Assumed Health Care Cost Trend Rates

Increase 

 

Decrease 

 

 

 

(a)

Effect on Service Cost + Interest Cost

$19,948

 

$(17,221)

 

 

 

(b)

Effect on Postretirement Benefit Obligation

$185,949

 

$(162,342)

 

 



Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2008

2007

2006

2005

(1)

Plan Assets

 

 

 

 

 

(a)

Equity Securities

N/A

N/A

N/A

N/A

 

(b)

Debt Securities

N/A

N/A

N/A

N/A

 

(c)

Real Estate

N/A

N/A

N/A

N/A

 

(d)

Other

N/A

N/A

N/A

N/A

 

(e)

Total

N/A

N/A

N/A

N/A



Cash Flows

 

 

 

 

 

 

 

(1)

Expected Contributions for Fiscal Year Ending 12/31/2008

 

 

 

(a)

Expected Employer Contributions

 

 

 $88,176

 

(b)

Expected Employee Contributions

 

 

 $30,968

 

 

 

 

 

 

(2)

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

 

 

 

 

 

 

 

Total

Medicare Part-D Reimbursement

Employee

Employer

 

(a)

12/31/2008

 $126,474

 $7,330

 $30,968

 $88,176

 

(b)

12/31/2009

 $130,300

 $8,172

 $33,442

 $88,686

 

(c)

12/31/2010

 $166,738

 $8,678

 $39,755

 $118,305

 

(d)

12/31/2011

 $180,399

 $9,266

 $41,073

 $130,060

 

(e)

12/31/2012

 $204,537

 $9,819

 $45,314

 $149,404

 

(f)

12/31/2013 – 12/31/2017

 $1,136,086

 $66,675

 $253,092

 $816,319

 

 

 

 

 

 

 

 

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/08

$0



Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2007

 

2006

 

2005

(1)

Market-Related Value of Assets

 N/A

 

 N/A

 

 N/A

(2)


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

-

 

-

 

-

(3)

Alternative Amortization Methods Used to Amortize

 

 

 

 

 

 

(a)

Prior Service Cost

Straight Line

 

Straight Line

 

Straight Line

 

(b)

Unrecognized Net (Gain) or Loss

Straight Line

 

Straight Line

 

Straight Line

(4)

Average Future Service

10.90

 

11.10

 

13.35

(5)


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

None

 

None

 

None

(6)

Description of Special or Contractual Termination Benefits Recognized During the Period

N/A

 

N/A

 

N/A

(7)

Cost of Benefits Described in (6)

N/A

 

N/A

 

N/A

(8)

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

N/A

 

N/A

 

N/A

(9)

Measurement Date Used

December 31, 2007

 

December 31, 2006

 

December 31, 2005


Discount Rate Assumption

The discount rate assumption used to determine the postretirement benefit obligations is based on current yield rates in the double A bond market.  

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


Actuarial Equivalent

In determining "Actuarial Equivalence," a prescription drug pricing tool was used. This tool allowed us to determine the estimated Per Member Per Month (PMPM) prescription drug cost for both the Company plan and the Medicare plan.  The two PMPM's were adjusted for monthly retiree contributions.  We assumed that 60% of the monthly combined medical and prescription drug retiree contribution for the Company plan applies towards prescription drugs. Because the subsidy is the same regardless of the cost sharing structure (unless the plan is not "Actuarial Equivalent"), in general a plan that has higher cost sharing would reduce their annual cost as a percentage greater than a plan would that has lower cost sharing.

 

Voluntary Prescription Drug Coverage

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


C. Health Plan

In December 2003, the Company became fully insured for its employee and retiree’s medical insurance. Net health care benefits paid by the Company were approximately $1.8 million in 2007, $1.7 million in 2006 and $1.6 million in 2005 excluding administrative and stop-loss insurance.


D. 401K Plan

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


For new hires not eligible for the defined benefit pension plan, we established an employer match to the employee’s contribution to their 401K plans. It provides for a company match of 50% for each dollar contributed by the employee, up to 6% of their salary, for a Company contribution of up to 3%. Beginning in 2007, for non-union employees the plan was enhanced to provide a company match of 100% for the first 2% of an employee’s contribution, and a match of 50% for the next 4% of an employee’s contribution, for a total company match of up to 4%. This enhanced match was successfully negotiated with our six union contracts in 2007. Employees are automatically enrolled at 3% contribution, with the option of opting out, and are eligible for the company match after six months of continuous service, with vesting of 100% after three years of continuous service.  

E. Employee Stock Purchase Plan

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



13.   Segment Information


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

 

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


Business segment information for 2007, 2006 and 2005 is summarized as follows:


(Dollars in thousands)

 

2007

 

2006

 

2005

Revenues

 

 

 

 

 

 

Natural gas

$

64,850 

71,139 

69,094 

Electric

 

55,521 

 

48,527 

 

47,450 

Propane gas

 

16,171 

 

15,115 

 

13,741 

Consolidated

$

136,542 

134,781 

130,285 

Operating income, excluding income tax

 

 

 

 

 

 

Natural gas

$

4,647 

6,118 

6,049 

Electric

 

2,653 

 

3,053 

 

3,502 

Propane gas

 

1,521 

 

1,006 

 

1,086 

Consolidated

$

8,821 

10,177 

10,637 

Identifiable assets

 

 

 

 

 

 

Natural gas

$

99,295

93,689 

96,106 

Electric

 

54,202

 

52,251 

 

51,317 

Propane gas

 

19,371

 

19,239 

 

19,567 

Common

 

19,476

 

16,055 

 

15,676 

Consolidated

$

192,344

181,234 

182,666 

Depreciation and amortization

 

 

 

 

 

 

Natural gas

$

4,374 

4,095 

3,928 

Electric

 

2,714 

 

2,610 

 

2,404 

Propane gas

 

898 

 

720 

 

621 

Common

 

300 

 

317 

 

313 

Consolidated

$

8,286 

7,742 

7,266 


Construction expenditures

 

 

 

 

 

 

Natural gas

$

11,134 

7,643 

6,357 

Electric

 

4,387 

 

3,184 

 

3,775 

Propane gas

 

773 

 

1,885 

 

2,133 

Common

 

446 

 

404 

 

176 

Consolidated

$

16,740 

13,116 

12,441 

 

 

 

 

 

 

 

Income tax expense

 

 

 

 

 

 

Natural gas

$

730 

1,336 

1,283 

Electric

 

430 

 

546 

 

666 

Propane gas

 

272 

 

110 

 

245 

Common

 

265 

 

246 

 

93 

Consolidated

$

1,697 

2,238 

2,287 


14.

Quarterly Financial Data (Unaudited)


The quarterly financial data presented below reflects the influence of seasonal weather conditions, the timing of rate increases and the migration of winter residents and tourists to Central and South Florida during the winter season.

 


(Dollars in thousands, except per share amounts):

First Quarter

Second Quarter

Third Quarter

Fourth Quarter

2007

 

 

 

 

 

 

 

 

Revenues

$

38,612 

32,468 

31,641 

33,821

Gross profit

$

13,843 

11,769 

11,062 

12,047

Operating income

$

3,738 

1,596 

1,414 

2,073

Earnings before income taxes

$

2,827 

607 

          519 

1,045

Net Income

$

1,798 

410 

355 

738

Earnings per common share (basic and diluted)

$

 0.30 

0.07 

0.06 

0.12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2006

 

 

 

 

 

 

 

 

Revenues

$

43,410 

29,975 

29,535 

31,861 

Gross profit

$

14,197 

11,499 

10,987 

12,127 

Operating income

$

4,528 

2,065 

1,263 

2,321 

Earnings before income taxes

$

3,507 

1,162 

          384 

1,354 

Net Income

$

2,221 

738 

335 

875 

Earnings per common share (basic and diluted)

$

 0.37 

0.12 

0.05 

0.14 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 




 


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Directors and Shareholders of FPU:


We have audited the accompanying consolidated balance sheets and statements of capitalization of Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation as of December 31, 2007 and 2006 and the related consolidated statements of income, comprehensive income, common shareholders' equity and cash flows for each of the three years in the period ended December 31, 2007.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and schedules, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Florida Public Utilities Company and its wholly-owned subsidiary, Flo-Gas Corporation at December 31, 2007 and 2006, and the results of its operation and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.  


As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007, the Company adopted Financial Accounting Standard Board (FASB) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)” and FASB Staff Position No. FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”



BDO Seidman, LLP

Certified Public Accountants

West Palm Beach, Florida

March 25, 2008



Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


None


Item 9A.

Controls and Procedures


Disclosure Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2007. Based on evaluation, our CEO and CFO have concluded that, as of December 31, 2007, our disclosure controls and procedures were effective in that they provide reasonable assurance that information required to be disclosed by us in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.


Management’s annual report on internal control over financial reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on such assessment and those criteria, management believes that the Company’s internal control over financial reporting was effective as of December 31, 2007.


Changes in Internal Control Over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this annual report.





PART III


Item 10.

Directors, Executive Officers and Corporate Governance


Information required by this item concerning directors and nominees of the Registrant will be included under the caption "Information About Nominees and Continuing Directors" in the Registrant's Proxy Statement for the 2008 Annual Meeting of Shareholders (the “2008 Proxy Statement”) and is incorporated by reference herein.  Information required by this item regarding the Audit Committee will be included under the caption “Board of Directors and Committees-Audit Committee” in the 2008 Proxy Statement and is incorporated by reference herein.  Information required by this Item regarding the code of ethics will be included under the caption “Board of Directors and Committees – Corporate Governance and Communication with Shareholders” in the 2008 Proxy Statement and is incorporated by reference herein. Information required by this Item regarding compliance with Section 16(a) of the Exchange Act will be set forth in the 2008 Proxy Statement under “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated by reference herein. Information required by this Item concerning executive officers is set out in Part I of this Form 10-K, above.


Item 11.

Executive Compensation


Information required by this Item concerning executive compensation is included under the captions “Board of Directors and Committees – 2007 Director Compensation”, "Executive Compensation", and “Compensation Committee Interlocks and Insider Participation” in the 2008 Proxy Statement and is incorporated by reference herein.


Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


Information required by this Item concerning the security ownership of certain of the Registrant's beneficial owners and management is included under the caption "Security Ownership of Management and Certain Beneficial Owners" in the 2008 Proxy Statement and is incorporated by reference herein.  See Item 5 above for equity compensation plan information, which is incorporated by reference herein.


Item 13.

Certain Relationships and Related Transactions and Director Independence


Information required by this Item concerning director independence is included under the caption “Board of Directors and Committees – Board of Directors” in the 2008 Proxy Statement and is incorporated by reference herein.  There were no transactions to report under Item 404 of Regulation S-K.


Item 14.

Principal Accountant Fees and Services


Information required by this Item is set forth in the Registrant’s 2008 Proxy Statement under the caption “Principal Accountant Fees and Services” and is incorporated by reference herein.



PART IV



Item 15.

Exhibits, Financial Statement Schedules


(a)

The following documents are filed as part of this report:


(1)

Financial Statements

The following consolidated financial statements of the Company are included herein and in the Registrant's 2007 Annual Report to Shareholders:


Consolidated Statements of Income

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Capitalization

Consolidated Statements of Common Shareholders' Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm


(2)

Financial Statement Schedules

The following valuation and qualifying accounts table is included in Note 1.I. herein and in the Registrant’s 2007 Annual Report to Shareholders:


Allowance for Doubtful Accounts


(3)

Exhibits


3(i)

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


3(ii)

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


4(a)

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


4(b)

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


 4(c)

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


10(a)

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

 

10(b)

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


10(c)

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


10(d)

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


10(e)

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


10(f)

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


10(g)

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


10(h)

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


10(i)

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


10(j)

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


10(k)

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


10(l)

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

 

10(m)

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


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


10(o)

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

 

10(s)*

Contract for the Agreement for Generation Services by and between FPU and Gulf Power Company dated December 28, 2006, effective January 1, 2008 (Incorporated by reference as Exhibit 10(s) on FPU’s annual report on Form 10-K for the year ended December 31, 2006)


10(t)

Agreement for the purchase of land in south Florida, dated July 5, 2007. (Incorporated by reference as Exhibit 10.1 to our Form 10-Q, for the quarter ended June 30, 2007)


10(u)

Agreement for the Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 2/29/2016, Contract No. 107033 (Incorporated by reference as Exhibit 10.1 to our Form 10-Q, for the quarter ended on September 30, 2007)


10(v)

Agreement for Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 3/31/2022, Contract No. 107034 (Incorporated by reference as Exhibit 10.2 to our Form 10-Q, for the quarter ended on September 30, 2007)


10(w)

Agreement for Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 2/29/2016, Contract No. 107035 (Incorporated by reference as Exhibit 10.3 to our Form 10-Q, for the quarter ended on September 30, 2007)


10(x)

Agreement with Chevron Natural Gas dated December 13, 2007.


10(y)

Amendment to physical sale Agreement with Inergy Propane, LLC dated October 31, 2007


10(z)

Agreement with Crosstex Gulf Coast Marketing LTD dated December 14, 2007.

 

10(aa)# Employment Agreement between the Company and John T. English dated March 31, 2006, amended October 22, 2007


10(ab)#

Employment Agreement between the Company and Charles L. Stein dated March 31, 2006, amended October 22, 2007

 

10(ac)# Employment Agreement between the Company and George M. Bachman dated March 31, 2006, amended October 22, 2007


14

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


16

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


21    

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


23    

Independent Registered Public Accounting Firm’s Consent BDO Seidman LLP


31.1

Certification of Principal Executive Officer (302)


31.2

Certification of Principal Financial Officer (302)


32

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



#Denotes management contract or compensatory plan or arrangement

 

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



SIGNATURES


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


FLORIDA PUBLIC UTILITIES COMPANY



       /s/ George M. Bachman

 

George M. Bachman, Chief Financial Officer

(Duly Authorized Officer)


Date: March 25, 2008


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.


/s/ John T. English

Date:  March 25, 2008

John T. English

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

Director (Principal Executive Officer)


/s/ George M. Bachman

Date:  March 25, 2008

George M Bachman, Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)


/s/ Ellen Terry Benoit

Date:  March 25, 2008

Ellen Terry Benoit, Director


/s/ Richard C. Hitchins

Date:  March 25, 2008

Richard C. Hitchins, Director


/s/ Dennis S. Hudson III

Date:  March 25, 2008

Dennis S. Hudson III, Director


/s/ Paul L. Maddock, Jr.

Date:  March 25, 2008

Paul L. Maddock, Jr., Director


/s/ Troy W. Maschmeyer, Jr.

Date:  March 25, 2008

Troy W. Maschmeyer, Jr., Director












FLORIDA PUBLIC UTILITIES COMPANY

EXHIBIT INDEX

Regulation S-K

Item Number


10(t)

Agreement for the purchase of land in south Florida, dated July 5, 2007.


10(u)

Agreement for the Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 2/29/2016, Contract No. 107033


10(v)

Agreement for Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 3/31/2022, Contract No. 107034


10(w)

Agreement for Firm Transportation Service with Florida Gas Transmission, for services beginning 11/01/07, expiring 2/29/2016, Contract No. 107035


10(x)

Agreement with Chevron Natural Gas dated December 13, 2007.


10(y)

Amendment to physical sale Agreement with Inergy Propane, LLC dated October 31, 2007


10(z)

Agreement with Crosstex Gulf Coast Marketing LTD dated December 14, 2007.



10(aa) #

       Employment Agreement between the Company and John T. English dated March 31, 2006, amended October 22, 2007


10(ab) #

       Employment Agreement between the Company and Charles L. Stein dated March 31, 2006, amended October 22, 2007


10(ac) #

Employment Agreement between the Company and George M. Bachman dated March 31, 2006, amended October 22, 2007


23    

Independent Registered Public Accounting Firm’s Consent BDO Seidman LLP


31.1

Certification of Principal Executive Officer (302)


31.2

Certification of Principal Financial Officer (302)


32

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

  



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