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Florida Public Utilities Company 10-K 2009
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, 2008

OR

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

For the transition period from ______________________ to _________________________


Commission file number

001-10608

 


Florida Public Utilities Company

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


Florida

 

59-0539080

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification 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

 

NYSE Amex



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.   [  ]


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

[  ]

Smaller reporting company

[X]

(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 30, 2008, 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 NYSE Amex) was approximately $69,085,000.


On March 2, 2009, 6,116,505 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 12, 2009 Annual Meeting of Shareholders are incorporated by reference in Part III hereof.



TABLE OF CONTENTS


PART I

Item 1

Business

Item 1A

Risk Factors

Item 1B

Unresolved Staff Comments

Item 2

Properties

Item 3

Legal Proceedings

Item 4

Submission of Matters to a Vote of Security Holders Executive Officers of the Registrant


PART II

Item 5

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 6

Selected Financial Data

Item 7

Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 7A

Quantitative and Qualitative Disclosures about Market Risk

Item 8

Financial Statements and Supplementary Data

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A

Controls and Procedures


PART III

Item 10

Directors, Executive Officers and Corporate Governance

Item 11

Executive Compensation

Item 12

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

Item 13

Certain Relationships and Related Transactions, and Director Independence

Item 14

Principal Accountant Fees and Services


PART IV

Item 15

Exhibits, Financial Statement Schedules

Signatures

Exhibit Index


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 12,000 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 Palm Beach, West Palm Beach, Royal Palm Beach, Palm Beach Gardens, North Palm Beach, Jupiter, Riviera Beach, Lake Worth, 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, Flagler County, parts of Lake County and Orange County and other areas near these cities and counties.  Our previous separate West Florida Division, which provides propane gas to customers in Dunnellon, Inglis, Crystal River, Inverness, Brooksville and other areas near these cities, is now consolidated with our Central Florida Division.

(3)

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

(4)

Northeast Florida Division - provides electricity to Fernandina Beach/Amelia Island in Nassau County and propane gas to customers in Fernandina Beach, Jacksonville, Callahan, Yulee and other areas within Nassau, Duval and Clay counties.


Business Environment

The historic growth that had 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 a reliable and environmentally friendly alternative energy source in the event of a power outage. During 2008, the cost of natural gas and propane gas was extremely volatile due to changes in the cost of crude oil and the economic downturn.


Historically, our cost of fuel in the electric segment had not been impacted by market fluctuations due to favorable long-term fixed price contracts for purchasing electricity. However, our long-term contracts terminated at the end of 2006 for our Northeast division and at the end of 2007 for our Northwest division. The new contracts in place have pricing closer to current market prices. As a result of these increased fuel costs, our cost of electricity sold significantly increased.  This does not directly impact our income from operations as increased fuel costs are passed through to the customers; however, this likely contributed to customers using less electricity which in turn decreased 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 15 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 to transport our natural gas supplies through its pipeline into peninsular Florida. Florida Gas Transmission 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 Florida Gas Transmission. We pass all fuel costs on to our customers at cost.  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 cost of gas.


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 and thus lower our sales.


The natural gas industry has not been deregulated in the state of Florida. Our current portfolio of natural gas customers is reasonably diverse, with the largest customer using natural gas for the generation of electricity.  We were 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).  The cost of electricity is passed through to customers at cost.


During 2006 we completed negotiations with JEA and executed final contracts for the supply of electricity in our Northeast division beginning on January 1, 2007 and our Northwest division from Gulf Power Company beginning on January 1, 2008. Both these contracts expire on December 31, 2017. 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.


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 in 2008.


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. No propane gas customer represented more than ten percent of our 2008 propane revenues.


Strategy

Our strategy is to leverage our expertise in the natural gas, electric and propane gas distribution business to assist us in consistently meeting our customers’ expectations. Our core focus for natural gas is customer retention and improving our market share in areas that are either on or near our natural gas mains. For propane, we are concentrating on retention, load growth and increasing market share in existing communities known to have high concentrations of propane gas users. In electric, our strategy is to educate our customers as to how our energy conservation programs may benefit them long term and ultimately reduce electric usage. For all areas of operations, we continue to strive and focus on excellent customer satisfaction and service.

 

Competition

We do not face substantial competition in our electric divisions.  This is because no competitor can 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 regulatory 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, 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 but not guarantee 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 including pension and medical expenses 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.  The FPSC is likely to grant rate increases to offset increased expenditures necessary for business operations; however, the process can take up to eight months from the filing date.


The FPSC approved an annual electric final rate increase of approximately $3.9 million effective May 22, 2008.  Interim rate relief for partial recovery of the increased expenditures was approved by the FPSC on October 23, 2007. Interim rates were effective in November of 2007 up until May 22, 2008, the date our final rates went into effect.  The increase produced additional annual revenues of approximately $800,000.


We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase in our natural gas segment. This request included recovery of increased expenses and some capital expenditures since our last rate proceeding in 2004. Finalization of this request and approval, if any, of a natural gas base rate increase would not occur until mid 2009. Interim rates which are expected to produce additional annual revenues of approximately $1 million went into effect for meter readings on and after March 12, 2009. Interim rates are collected subject to refund, pending the resolution of the issues and the outcome of the final rate proceeding.


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, the United States Environmental Protection Agency 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 Florida Department of Environmental Protection and the Environmental Protection Agency 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.


The City of Marianna is currently reviewing the franchise agreement with the Company that is up for renewal in 2010. The City has hired a Consultant to review the feasibility of purchasing the portion of our electric system that is within the city limits. If the City elects to purchase the Marianna portion of the distribution system, it would be required to pay the fair market value, and would need to invest in the infrastructure to operate this limited facility. If the franchise is not renewed and the City purchases this portion of our electric system, the Company would have a gain in the year of the acquisition.  Ongoing financial results would be negatively impacted from the loss of this operating area within our electric operations. At this time we do not believe the City will find it prudent and we expect the Marianna Franchise will be renewed.


Seasonality

The effects of seasonal weather conditions and the migration of winter residents and tourists to Florida during the winter season impact our income.


Employees

As of February 28, 2009, we employed 348 employees, including 10 part-time and 8 temporary employees. Of these employees, 169 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 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.


The FPSC regulates many aspects of our natural gas and electric operating segments, including the retail rates we 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.


We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase of approximately $9.9 million annually in our natural gas segment. Interim rate relief was approved by the FPSC on February 10, 2009 for partial recovery of the increased expenditures. If the FPSC approves partial recovery instead of full recovery of the requested rate increase, the impact to our 2009 and future net operating income in our natural gas segment would be lower than anticipated.


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, 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 materially 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 alternative energy competitive forces for several years. We receive our supply of natural gas at thirteen city gate stations connected to an interstate pipeline system owned by Florida Gas Transmission, 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 but we are not utilizing that pipeline at this time.


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 and faces 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.


Florida Gas Transmission’s pipeline system transports all of our natural gas.  Florida Gas Transmission is owned by Citrus Corporation, which is jointly owned by CCE Holdings, LLC, a joint venture of Southern Union Company and GE Commercial Finance Energy Financial Services.  Our ability to receive a normal supply of natural gas could adversely affect earnings if there is an interruption in Florida Gas Transmission’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. Fuel costs could also increase as a result of economic conditions. Consumers reduce energy consumption as costs go up and the economy worsens. This adversely affects our unit sales. A further 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. Further construction and housing market declines can negatively impact our customer growth and customer retention. Loss of commercial customers due to bankruptcies and business closings which have been increasing in this declining economy adversely affects our unit sales.


As the downturn in the economy affects consumer spending, tourism in Florida may be adversely affected. If tourism is down, then the demand for the energy we supply is reduced. Changes in political climate, including terrorist activities, could further negatively impact our performance.


In addition, deterioration in the financial condition of our customers as a result of the economy could cause significant increase in our bad debt expense and related write-offs to our receivables, which would negatively impact our profitability.


We are vulnerable to the stock market and the impact to our pension liability.


The recent decline in the stock market and the impact to our pension liability and related contributions has been significant. Additional declines in the stock market and valuation of stocks could further impact our pension liability and contributions.


We are vulnerable to covenant violations which could impact our short-term line of credit or our ability to obtain additional short-term funding.


The general economic conditions and credit climate could impact our ability to obtain short-term debt financing as a result of potential violation of current covenants. The pension liability has increased significantly as a result of the continued decline in the stock market. As a result, we are approaching ratio limitations related to our current short-term debt covenants that if violated, could cause the bank to request immediate payment of our line of credit balance, or limit our ability to borrow as needed. There can be no assurance that we would be able to repay the line of credit without securing additional financing, which may not be available on reasonable terms or at all.

 

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 since price changes influence consumption.


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 Florida Department of Environmental Protection, the Environmental Protection Agency and other federal and state agencies.  We may incur material future expenditures in order to comply with the environmental laws and regulations.


We are currently involved in multiple environmental litigations that may have a material impact to our company. They are discussed in ‘Item 3, Legal Proceedings’.


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 from 2010 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 electric 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, 2008, 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 part in 2010, 2015 and 2023. We are committed to pay demand or similar fixed charges monthly through 2023 related to these 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.


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 customer retention and improved market share in areas that are either on or near our natural gas mains. Our outlook is based on our expectation that we will be successful in finding attractive opportunities for growth, and we will retain our current customer base through providing excellent customer service.  However, our efforts may not be successful. Our failure to effectively and efficiently manage our growth, as well as changes in our business strategies, may have a material adverse effect on our financial condition and results of operations.


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


We cannot 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 the Florida Business Corporation Act, 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 Florida Business Corporation Act 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 Florida Business Corporation Act 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 FPSC 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.


The financial performance of the Company may be adversely affected if our divisions are unable to successfully operate their facilities.


Our financial performance depends on the successful operation of our electric, natural gas and propane facilities. Operating these facilities involves many risks, including:


·

operator error or failure of equipment or processes;

·

operating limitations that may be imposed by environmental or other regulatory requirements;

·

labor disputes;

·

fuel or material supply interruptions;

·

compliance with mandatory reliability standards; and

·

catastrophic events such as fires, earthquakes, explosions, floods, droughts, hurricanes, terrorist attacks, pandemic health events such as an avian influenza, or other similar occurrences.


A decrease or elimination of revenues from any one of our facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition.


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. Current market conditions could severely limit our future ability to access capital. 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 available 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.


We are vulnerable to our franchise agreements not being renewed.


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. Ongoing financial results would be negatively impacted from the loss of certain operating areas within our electric or gas operations because of nonrenewal.


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 1,623 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 1,122 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 underground 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 is located.


All of our property is subject to a lien collateralizing our funded indebtedness under our Mortgage Indenture and Deed of Trust, as supplemented.


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 us in West Palm Beach, Florida upon which we previously operated a gasification plant. Pursuant to a Consent Order between the Company and the Florida Department of Environmental Protection effective April 8, 1991, the Company completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, the Company transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the Florida Department of Environmental Protection.


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


Negotiations between the Company and the Florida Department of Environmental Protection on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the complete extent or cost of remedial action that may be required. As of December 31, 2008, and subject to the limitations described above, the Company's remediation expenses, including attorneys' fees and costs, are projected to range from approximately $5.1 million to $18.3 million for this site.

Sanford Site

The Company owns a parcel of property located in Sanford, Florida, upon which a gasification plant was operated prior to our acquisition of the property. On March 25, 1998, the Company executed an Administrative Order on Consent with the four former owners and operators (collectively, the "Group") and the United States Environmental Protection Agency that obligated the Group to implement a Remedial Investigation/Feasibility Study and to pay the United States Environmental Protection Agency's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998. Work under the Remedial Investigation/Feasibility Study Administrative Order on Consent and Participation Agreement and an Escrow Agreement is now complete and the Company has no further obligations under either document.

In 2008, a revised Consent Decree was signed by all Group Members and the United States Environmental Protection Agency, providing for the implementation by the Group of the remedies the United States Environmental Protection Agency approved earlier for the site, which are set forth in the Records of Decision for Operable Units 1-3, and for the payment of the United States Environmental Protection Agency's past and future oversight costs. The Consent Decree was entered by the federal Court in Orlando and became effective on January 15, 2009; the parties to the Consent Decree are now obligated to implement the remedy approved by United States Environmental Protection Agency for the site.


In January 2007, the Company and other members of the Group signed a Third Participation Agreement, which provides for funding the remediation work specified in the Records of Decision for Operable Units 1-3 and supersedes and replaces the Second Participation Agreement.  The Company's share of remediation costs under the Third Participation Agreement is set at 5% of a maximum of $13 million, or $650,000. To date, the Company has contributed $100,000 of its total share of remediation costs under the Third Participation Agreement. It is currently anticipated that the total cost of the final remedy will exceed $13 million. The Company has advised the other members of the Sanford Group that we are unwilling at this time to agree to pay any sum in excess of the $650,000 committed by us in the Third Participation Agreement.


Several members of the Sanford Group recently concluded negotiations with two adjacent property owners to resolve damages that the property owners allege that they have/will incur as a result of the implementation of the EPA approved remedy. In settlement of these claims, members of the Sanford Group (excluding the Company) have agreed to pay specified sums of money to the parties. In one case, the settlement agreement requires the select members of the Sanford Group to purchase the third party's property for approximately $2 million; the third party then has an option to buy back the property after completion of the remedy for approximately the same amount. In the other case, the select members agreed to a lump sum payment of $428,000. The Company has refused to participate in the funding of the third party settlement agreements based on the contention that it did not contribute to the release of hazardous substances at the site giving rise to the third party claims.


As of December 31, 2008, the Company’s share of remediation expenses, plus the Company’s attorneys' fees and costs, are projected to be approximately $645,000 for this site. However, at this time, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept the Company’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for the site or will pursue a claim against the Company for a sum in excess of the $650,000 that FPUC has committed to fund the remedy.


Pensacola Site

The Company is the prior owner/operator of the former Pensacola gasification plant, located at the intersection of Cervantes Street and the Louisville and Nashville (CSX) Railroad line, Pensacola, Florida. Following notification on October 5, 1990, that the Florida Department of Environmental Protection had determined that the Company was one of several responsible parties for any environmental impacts associated with the former gasification plant site, the Company entered into cost sharing agreements with three other responsible parties providing for the funding of certain contamination assessment activities at the site.


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

In March 1999, the United States Environmental Protection Agency requested site access in order to undertake an Expanded Site Inspection. The Expanded Site Inspection was completed by the United States Environmental Protection Agency's contractor in 1999 and an Expanded Site Inspection Report was transmitted to the Company in January 2000. The Expanded Site Inspection Report recommends additional work at the site. The responsible parties met with the Florida Department of Environmental Protection on February 7, 2000 to discuss the United States Environmental Protection Agency's plans for the site. In February 2000, the United States Environmental Protection Agency indicated preliminarily that it will defer management of the site to the Florida Department of Environmental Protection; as of July 31, 2008, the Company has not received any written confirmation from the United States Environmental Protection Agency or the Florida Department of Environmental Protection regarding this matter. Prior to receipt of the United States Environmental Protection Agency's written determination regarding site management, we are unable to determine whether additional field work or site remediation will be required by the United States Environmental Protection Agency and, if so, the scope or costs of such work.


As of December 31, 2008, the Company’s share of remediation expenses for the site, including attorney’s fees and costs, are projected to be approximately $27,000.


Key West Site

Between 1927 and 1938, the Company owned and operated a gasification plant on Catherine Street, 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 was prepared by a consultant jointly retained by the Company and the current site owner and was delivered to the Florida Department of Environmental Protection. The Preliminary Contamination Assessment Report reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, the Florida Department of Environmental Protection notified the Company that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." the Florida Department of Environmental Protection then referred the matter to its Marathon office for consideration of whether additional work would be required by the Florida Department of Environmental Protection's district office under Florida law. As of December 31, 2008, the Company has received no further communication from the Florida Department of Environmental Protection with respect to the site. At this time, we are unable to determine whether additional field work will be required by the Florida Department of Environmental Protection and, if so, the scope or costs of such work. In 1999, the Company received an estimate from its consultant that additional costs to assess and remediate the reported impacts would be approximately $166,000. As of December 31, 2008 and assuming the current owner shared in such costs according to the allocation agreed upon by the parties for the Preliminary Contamination Assessment Report, the Company's share of remediation expenses, including attorneys' fees and costs, is projected to be $93,000 for this site.


Item 4.

Submission of Matters to a Vote of Security Holders


None.





Executive Officers of the Registrant


The following sets forth certain information about the executive officers of the Company as of February 17, 2009.


Name

Age

Position

Date

 

 

 

 

John T. English

65

Chairman of the Board

2006 - Present

 

 

Chief Executive Officer

1998 - Present

 

 

President

1997 - Present

 

 

Chief Operating Officer

1997 - 2000

 

 

 

 

Charles L. Stein

59

Chief Operating Officer

2001 – Present

 

 

Senior Vice President

1997 – Present

 

 

 

 

George M. Bachman

49

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 August 21, 2008 with a term through August 21, 2011, 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 NYSE Amex under the symbol FPU. The quarterly dividends declared and the reported last low and high price ranges per share of our common stock as reported by the NYSE Amex for the most recent two years were as follows:


 

2008

 

2007

 

Stock Prices

Dividends

 

  Stock Prices

Dividends

Quarter ended

Low

 

High

Declared

 

Low

 

High

Declared

March 31 

$10.75 

 

$12.35 

$0.1125 

 

$11.90 

 

$13.50 

$0.1075 

June 30 

10.34 

 

12.25 

0.1175 

 

11.01 

 

12.91 

0.1125 

September 30 

  11.40 

 

13.12 

0.1175 

 

11.15 

 

12.49 

0.1125 

December 31 

8.00 

 

13.09 

0.1175 

 

11.24 

 

12.83 

0.1125 


As of January 28, 2009, there were approximately 3,741 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, debt covenants, 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, 2008, approximately $10.2 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

134,750*

Equity compensation plans not approved by security holders

    -

Total

                         134,750

 

 

* This includes 13,399 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 1,351 treasury shares for the Employee Stock Purchase Plan; 5,000 of which were approved and added on June 27, 2008. Also included are 120,000 new shares for the Employee Stock Purchase Plan that was adopted by the Board of Directors on March 11, 2008 and was approved at the 2008 meeting of shareholders.


Item 6.

Selected Financial Data


(Dollars in thousands, except per share data)

Years Ended December 31,

 

2008 

 

2007 

 

2006 

 

2005 

 

2004(2)

Revenues  (1)

168,548 

136,542 

134,781 

130,285 

110,131 

 

 

 

 

 

 

 

 

 

 

 

Gross profit  (1)

51,227 

48,721 

48,810 

47,481 

40,781 

Net income

3,486 

3,301 

4,169 

4,248 

3,594 

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share (basic and diluted):

 0.57 

0.54 

0.69 

0.71 

0.60 

 

 

 

 

 

 

 

 

 

 

 

Dividends declared per common share

0.47 

0.45 

0.43 

0.41 

0.40 

 

 

 

 

 

 

 

 

 

 

 

Total assets   (1)

208,931 

192,344 

 181,234 

182,666 

170,503 

Utility plant – net

142,325 

138,372 

129,211 

123,061 

117,191 

Current debt

14,156 

12,531 

3,466 

9,558 

5,825 

Long-term debt

47,920 

49,363 

50,702 

50,620 

50,538 

Common shareholders' equity

48,512 

48,946 

47,572 

45,503 

43,213 

 

 

 

 

 

 

 

 

 

 

 

Note to the Selected Financial Data:

 

 

 

 

 

 

 

 

 

 

(1)

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

 

(2)

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


Revenues and Gross Profit Summary

The Florida Public Service Commission (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. We define gross profit as operating revenues less fuel, conservation and revenue-based taxes that are passed directly through to customers. Because gross profit excludes these cost recovery revenues, we believe it provides a more meaningful basis for evaluating utility revenue. 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,

 

2008

2007

2006

Natural Gas

 

 

 

Revenues

$72,624 

$64,850 

$71,139 

Cost of fuel and other pass through costs

46,039 

38,251 

43,909 

Gross Profit

$26,585 

$26,599 

$27,230 

   Units sold: (MDth)

5,966 

6,042 

 6,230 

   Customers (average for the period)

51,957 

51,589 

51,211 

Electric

 

 

 

Revenues

$78,655 

$55,521 

$48,527 

Cost of fuel and other pass through costs

61,565 

41,142 

34,259 

Gross Profit

$17,090 

$14,379 

$14,268 

   Units sold: (MWH)

739,532

810,604 

849,124 

   Customers (average for the period)

31,295 

31,074 

30,635 

Propane Gas

 

 

 

Revenues

$17,269 

$16,171 

$15,115 

Cost of fuel

9,717 

8,428 

7,803 

Gross Profit

$ 7,552 

$7,743 

$7,312 

Units sold:  (MDth)

552 

 597 

621 

    Customers (average for the period)

12,463 

13,140 

13,048 

Consolidated

 

 

 

Revenues

$168,548 

$136,542 

$134,781 

Cost of fuel and other pass through costs

117,321 

87,821 

85,971 

Gross Profit

$ 51,227 

$ 48,721 

$ 48,810 

Customers (average for the period)

95,715 

95,803 

94,894 


 


Natural Gas

Natural gas revenues increased $7.8 million, or 12% in 2008 over 2007 due to increases to recover fuel costs, which are passed through to customers.  Our gross profit, which excludes expenses directly passed through to customers, remained flat as compared to the prior year.  The percentage of gross profit to total revenues decreased by 4% compared to the prior year due to increases in our cost of fuel and the resulting increased pass-through revenue. The average customer growth increased marginally in 2008 compared to 2007 primarily due to the conversion of a large community from propane to natural gas in September 2007.  In spite of colder weather, units sold decreased by 1% most likely as the result of conservation measures taken by our customers due to higher fuel costs, the downturn in the housing market, and the economy as a whole.


We recorded additional 2006 over-earnings of $135,000 which reduced revenues and gross profit in the third quarter of 2008. The FPSC approved finalization of the 2006 over-earnings on September 29, 2008 and ordered the Company to fund its natural gas storm reserve to offset any future storm costs.


Natural gas revenues decreased $6.3 million, or 9% in 2007 over 2006. As the cost of natural gas declined, the revenues 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%.  The percentage of gross profit to total revenues increased by 3% compared to the prior year due to increases in our cost of fuel and the resulting increased pass-through revenue.  Although customer growth was up in 2007 compared to 2006, we experienced a 3% decrease in units sold primarily due to milder weather.


Electric

Electric revenues increased $23.1 million or 42% in 2008 over 2007.  The cost of fuel and other costs passed through to customers contributed to $20.4 million of the increase, as a result of higher fuel costs reflected in new fuel contracts effective January 1, 2008 in our Northwest division. Gross profit increased $2.7 million, or 19% compared to 2007 primarily due to the recent base rate increase. The percentage of gross profit to total revenues decreased by 4% compared to the prior year due to increases in our cost of fuel and the resulting increased pass-through revenue. This was despite a 5% decrease in units sold to our non-industrial customers. The decrease in consumption may be the result of conservation measures taken by our customers and the overall downturn in the economy.


Gross profit was not materially impacted from reduced consumption as this was forecasted in our recent electric rate increase approved in April 2008.  Rates were set to compensate for the anticipated reduction in units sold due to significant increases in fuel costs. The FPSC approved the final annual electric rate increase of approximately $3.9 million effective May 22, 2008.  An interim rate increase of approximately $800,000 annually was in effect from November 22, 2007 until the final rates went into effect.


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 higher fuel costs reflected in 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.  The percentage of gross profit to total revenues decreased by 4% compared to the prior year due to increases in our cost of fuel and the resulting increased pass-through revenue. 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.


Propane Gas

Propane revenues increased $1.1 million, or 7%, primarily as a result of increased rates to our customers to recover $1.3 million in increased fuel costs. Gross profit declined by $191,000 or 2% in 2008 compared to 2007 as a result of a 7.5% decrease in units sold. In spite of colder temperatures, units sold declined as a result of the conversion of a large development from propane to natural gas in September 2007.  In addition, the downturn in the housing market and the economy had a negative impact on customer growth and usage per customer. Additionally, we recorded an inventory loss adjustment of approximately $110,000 in 2008. This loss may have been caused primarily by faulty metering equipment and measurement errors.


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


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,

 

2008 

2007

             2006

Natural gas

$   23,022 

$   21,951 

$   21,112 

Electric

12,885 

   11,726 

     11,215 

Propane gas

6,211 

     6,223 

     6,306 

Total Operating Expenses

$  42,118 

 $   39,900 

 $   38,633 


Natural Gas

Natural gas operating expenses increased $1.1 million, or 5%, in 2008 as compared with 2007. Administrative expenses account for $401,000 of this increase and are discussed in a separate section below. We experienced a $449,000 increase in expenses relating to uncollectible accounts which may be another consequence of the declining economy. To address this issue, we have increased our collection efforts and are enforcing deposit requirements. The increase includes a large write off of $164,000 for a commercial customer bankruptcy. Depreciation expense increased $194,000 due to normal plant growth and the conversion of the Summer Glen development from propane to natural gas in September of 2007.


To help offset increased expenditures, we reduced selling expenses by eliminating sales positions. Additionally, other operating expenses decreased as a result of the slowdown in the economy and housing market. We experienced fewer installations of gas lines to residential customers as new construction activities continued to decline.  The combined impact was a decrease in our other operating and sales expenses of $269,000.


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.


Electric

Electric operating expenses increased $1.2 million, or 10%, in 2008 as compared with 2007. Administrative expenses account for $106,000 of the increase and are discussed in a separate section below. Operating expenses increased by $192,000 due to the addition of an engineering position and due to the additional substation, line and lighting inspections necessary to comply with new operating requirements. As a result of storm hardening initiatives recently mandated by the FPSC, tree trimming and other maintenance expenses increased by $231,000. New electric depreciation rates, that were effective January 1, 2008, and normal plant growth increased depreciation expense by $495,000. A portion of the 2008 depreciation expense was not recovered in 2008 in electric rates due to the timing of final rate increase.


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.


Propane Gas

Propane gas operating expenses remained flat in 2008 as compared with 2007. We experienced decreased selling expenses of $146,000 as a result of a continued drop in demand from the slowdown of new construction in South Florida and the overall economy.


Additionally, other operating expenses and depreciation expense decreased $133,000 and $75,000, respectively, due in a large part to a conversion of customers in our central Florida division from propane to natural gas in the fourth quarter of 2007.  These expenses were offset by increased general administrative expenses of $236,000, discussed in a separate section below, and increased customer accounts expense of $67,000 relating to increased bad debts, due to the downturn in the economy.


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 SummerGlen 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.


Administrative Expenses

Administrative expenses which includes allocations for merchandising and jobbing, increased $743,000, or 7%, in 2008 over 2007. Approximately $500,000 of this increase was due to professional fees and expenses incurred in the second quarter of 2008 related to strategic development activity no longer ongoing.  The impact to net income for these expenses is approximately $312,000, or $.05 per share, for the year ending December 31, 2008. Pension and medical costs continued to outpace inflation, increasing $125,000 and $165,000, respectively. We experienced an increase to payroll and temporary staffing costs of $334,000 as a result of normal pay raises and additional temporary assistance related to tax work. These increases were partially offset by a drop in general liability expenses of $581,000, as discussed below, since claims in 2007 were above normal levels.


Administrative expenses increased $1 million, 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.

Total Other Income and Deductions

Other income and deductions include merchandise and service revenues and expenses; 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 expenses decreased by $582,000 and $472,000, respectively, resulting in decreased profit of $110,000 in 2008 as compared to 2007. We continue to face a slowdown in the construction industry and housing market, in addition to current economic conditions. This has reduced the demand for new merchandise and installations. Management does not anticipate the housing market or economy will rebound in 2009, and expects sales to stay suppressed.


In 2007, merchandise and services revenue and expenses decreased by $1.1 million and $1.3 million, respectively, although our overall profit increased $125,000, as compared to 2006. A lower number of product installations actually improved our profit margin on the installation side of our business. We had fewer customer owned tank installations and we discontinued generator sales, both of which are historically less profitable.  The slowdown in the construction industry and housing market, along with a quiet hurricane season, dramatically reduced the demand for new merchandise.


Interest Expense

Interest expense consists of interest on bonds, short-term borrowings, over earnings and customer deposits. In 2008, interest expense decreased $54,000. This is mainly due to a drop in tax related interest expense relating to prior year IRS audit findings and the related interest expense. Interest expense in long-term borrowing decreased due to the partial repayment of principal from a sinking fund payment. This was offset by increased short-term interest expense due to a higher balance on the line of credit.


Other

Income was generated in 2008 from a special project to build a propane facility for a fire rescue department. This is the primary reason for the $59,000 increase to other net non-operating income.


Income Taxes

Higher taxable income increased income tax expense by $106,000 in 2008 over 2007.


Liquidity and Capital Resources


Summary of Primary Sources and Uses of Cash

(Dollars in thousands)

Year Ended December 31,

 

2008 

2007

2006

Sources of Cash:

 

 

 

Operating activities, including working capital changes

$12,620 

$14,526 

$20,090 

Net proceeds on short-term debt

1,625 

7,656 

Other sources of cash

814 

923 

1,179 

Uses of Cash:

 

 

 

Construction expenditures

11,227 

16,740 

13,116 

Dividends paid

2,788 

2,681 

2,551 

Net payment on long-term & short-term debt

1,442 

6,092 

Other uses of cash

83 

290 

121 

     Net (use) source of cash

$ (481)

$  3,394 

$   (611)

 


Cash Flows


Operating Activities

Net cash flow provided by operating activities decreased by approximately $1.9 million in 2008 as compared to 2007.  This was caused by several factors:


·

Fuel costs increased over the prior year and we also refunded prior year over-recoveries. Both of these items caused a decrease in cash of $2.1 million compared to the prior year.

·

We experienced a $2.2 million decrease in cash as a result of higher receivables due to increased revenues.

·

We had a $2.2 million decrease in cash resulting from prepaid taxes primarily as a result of expected pension contributions to be made in 2009 for the 2008 plan year. We expect to receive this tax refund in the first half of 2009.

·

We experienced a $3.7 million increase in cash from reductions in current taxes paid compared to the prior year. The primary reason for this increase was depreciation true-ups for prior tax years. This partially offset the decrease to cash listed above.


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.


Investing Activities

Capital expenditures decreased in 2008 compared to 2007 by approximately $5.5 million. The majority of the decrease was a result of purchase of land for the future site of our South Florida operations facility for approximately $3.5 million in the prior year. During 2007, our Northwest Florida electric division incurred above normal expenditures of $265,000 for storm hardening projects, meter, and regulator purchases.  In our Northeast Florida electric division, $600,000 of 2008 scheduled electric transmission expenditures were delayed until 2009 due to contractor scheduling conflicts and specification changes.  In addition there was a significant reduction in expenditures for distribution facilities and installations this year because of the slowdown in the construction industry and economy.


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.


Financing Activities

Cash from short-term borrowings decreased by approximately $6.0 million in 2008, primarily due to increased borrowings in 2007 to fund the purchase of land for our South Florida division.  Cash of $1.4 million was used in 2008 for sinking fund payments due in the second quarter of this year.


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.


Capital Resources

We have a revolving line of credit with Bank of America which expires July 1, 2010.  Prior to March 2008, the available line of credit was $15 million with the ability to increase the limit to a maximum of $20 million upon 30 days notice. In March 2008, we amended our line of credit to allow us, upon 30 days notice, to increase our maximum credit line from $20 million to $26 million and to reduce the interest rate paid on borrowings by 0.10% or 10 basis points. In April 2008, we increased the currently available line of credit from $12 million to $15 million and at December 31, 2008, the balance outstanding was $12.7 million. We reserve $1 million of the line of credit to cover potential expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane gas facilities.


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 line of credit covenants with Bank of America include certain financial ratios, all of which are currently met. However, see ‘Covenants’ below under “Outlook and Subsequent Events”.


The line of credit, long-term debt and preferred stock as of December 31, 2008 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, 2008, such calculation would permit the issuance of approximately $49.7 million of additional bonds.


On October 14, 2008 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 2009.


We have $3.5 million in invested funds for payment of future environmental costs. We expect to use some or all of these funds in 2010 and 2011.


We expect to receive tax refunds of approximately $2.2 million in early 2009.  The primary reason for this refund is our planned pension contribution of $4.6 million for plan year 2008 expected to be made in 2009 as shown in Note 13A in the Notes to Consolidated Financial Statements.  This pension contribution is a deduction for tax purposes in 2008 calendar year; but was not known at the time of estimated tax payments made in calendar year 2008.


As of December 31, 2008 there was approximately $5.9 million in receivables from the 2003 sale of our water assets. We received an installment of $252,000 in February of 2009.  Final payment of principal and interest totaling $5.8 million is expected in February 2010.


Capital Requirements

Portions of our business are seasonal and dependent upon weather conditions in Florida. This 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 were originally expected to be higher in 2009 compared to 2008 by approximately $3.1 million. However, management has decided to reduce capital expenditures significantly when possible for 2009, which should lower capital expenditures to the 2008 level of $11.2 million or below.  Overall, 2008 experienced decreased capital investments due to the downturn in the economic climate and reduced construction levels.  The 2009 projected capital expenditures reflect normal spending levels required for replacement natural gas construction related to expected road construction and include $800,000 for system improvements and expansion within our natural gas segments.


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 $774,000 in 2009, with remaining payments, which could total approximately $9.1 million, net of investment proceeds, beginning in 2010. Annual long-term debt sinking fund payments of approximately $1.4 million will continue in 2009 for ten years.


The Company made a voluntary contribution in our defined benefit pension plan of $400,000 in 2008 for the 2007 plan and expects to make 2009 contributions of $4.6 million for the 2008 plan and $1.2 million for the 2009 plan. Refer to Note 13A in the Notes to Consolidated Financial Statements. We will continue to make contributions as required by the Pension Protection Act funding rules. As a result of the current economic climate and the impact to the stock market investments held within our pension plan, future contributions to our defined benefit pension plan are expected to increase. Annual contributions are expected to range between approximately $1.8 million and $5.9 million in each of the next five calendar years. Our total pension contributions over the next five years are anticipated to be approximately $15 million.  Annual pension expenses are projected to be between $1 million and $2 million per year over the next five years. The total expenses for this five year period are projected to be approximately $8 million.


In an effort to reduce anticipated pension costs and the pension liability, the Company is proposing to freeze this plan effective December 31, 2009. With the freeze, total pension expense and total pension contributions for the next five years are expected to be approximately $1 million and $12 million, respectively. As a result of the freeze, annual contribution payments are expected to be $3.7 million in 2010, $600,000 in 2011, $1.2 million in 2012 and $1.0 million in 2013.


We believe that cash from operations, coupled with short-term borrowings on our line of credit, will be sufficient to satisfy our operating expenses, normal construction expenditure and dividend payments through 2009; however we are considering equity or debt financing in 2009 or 2010. 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. 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 Franchise Marianna

The City of Marianna is currently reviewing the franchise agreement with the Company that is up for renewal in 2010. The City has hired a Consultant to review the feasibility of purchasing the portion of our electric system that is within the city limits. If the City elects to purchase the Marianna portion of the distribution system, it would be required to pay the fair market value, and would need to invest in the infrastructure to operate this limited facility. If the franchise is not renewed and the City purchases this portion of our electric system, the Company would have a gain in the year of the acquisition; but, ongoing financial results would be negatively impacted from the loss of this operating area within our electric operations. At this time we do not believe the City will find it prudent and expect it to renew the Marianna Franchise.


Storm Preparedness Expenses

Regulators continue to focus on hurricane preparedness and storm recovery issues for utility companies. Newly mandated storm preparedness initiatives have impacted our 2008 earnings and will continue to impact our operating expenses and capital expenditures in 2009. The current forecast is not expected to exceed additional annual expenditures of approximately $260,000. During the 2008 rate proceeding, these storm preparedness costs were approved and have been included in the base rates.  It is possible that additional regulation and rules will be mandated regarding storm related expenditures over the next several years.

Land Purchase

We purchased land for $3.5 million in July 2007 for a new South Florida operations facility.  We started preparing plans for site development of this property and may begin construction in the next one to three years.


We have a commitment to purchase land for approximately $200,000 adjacent to our Central Florida operations facility for additional parking. We expect to close on this land purchase in 2009.


Medical Insurance

We continue to experience increases in our medical insurance costs.  Management expects an increase of approximately $104,000, or 4%, in 2009 over 2008.  The combination of historical claims and the market trend resulted in an overall rate increase in 2009. The Company will continue to proactively identify healthcare options that will help control our overall medical costs and strive to assist our employees in improving their health.


Natural Gas Base Rate Proceeding

We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase of approximately $9.9 million annually in our natural gas segment. This request included recovery of increased expenses and some capital expenditures since our last rate proceeding in 2004. Finalization of this request and approval, if any, of a natural gas base rate increase would not occur until mid 2009.


Interim rate relief was approved by the FPSC on February 10, 2009 for partial recovery of the increased expenditures.  Interim rates which should produce additional annual revenues of approximately $1.0 million became effective for meter readings on and after March 12, 2009. The permanent rates may differ from the interim rates. The interim rates are collected subject to refund with interest.


If the FPSC approves partial recovery instead of full recovery of the requested rate increase, which includes recovery of increased expenses; return on capital expenditures; and a requested return on common equity, the impact to our 2009 and future net operating income in our natural gas segment would be lower than anticipated.


Natural Gas Depreciation Study

We filed a depreciation study with the FPSC in the fourth quarter of 2008 for our natural gas segment. We requested an implementation date to coincide with a change to our natural gas base rates expected to be effective mid 2009. We expect depreciation expense will increase approximately $400,000 annually beginning mid 2009, and expect full recovery for this increased expense in our rate increase.


Large Customer in NE Electric Division

A large industrial customer in our Northeast electric division filed for bankruptcy on January 26, 2009.


Although the average monthly gross profit from this customer was approximately $29,000 in 2008, the average total monthly bill including fuel costs for this customer was approximately $250,000. This customer has currently paid all outstanding amounts that were due as of December 31, 2008. The Company has reserved approximately $200,000 for this potential bad debt in the first quarter of 2009 awaiting the outcome of this bankruptcy proceeding. If the courts determine that we have to refund any prior payments, the Company may be required to write-off a portion of this customer’s receivables including fuel cost to our reserve. If a write off is required for this customer, the Company plans to request special treatment from the FPSC to defer the write-off of this receivable to bad debt expense until the Company’s next base rate proceeding and to amortize the write-off to bad debt expense over four years.


Bad Debt Expense

Management expects bad debt expense and related write-offs of receivables to continue increasing further in 2009 as a result of the current economic climate and the impact to our customers. We are not able to predict the impact to our financial results, but we do anticipate an increase to bad debt expense over the current levels.


Energy Efficiency Legislation

Regulators are focusing on several legislative issues involving the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 and related issues.  One major provision is the implementation of a renewable portfolio standard.   Since the Company is a non-generating utility with existing ten year all-requirements wholesale energy contracts, there is significant concern over the additional purchased power cost that may be required to comply with the standard.  Although this cost may be passed on to the customers through a rate increase, continued decrease in customer usage will have an impact on operations.  “Smart Grid Technology” is another item being considered that would require significant capital investment to develop, install and manage.  The Company understands the overall benefits from the legislation but the burden imposed on a small utility like ours is of particular concern.  The Company is continuing to communicate with the FPSC to find solutions that will work for the Company, while maintaining manageable electric rates for customers.


Covenants

We have historically met all our line of credit and fuel supplier covenants. As of December 2008 we were in violation of a covenant regarding our total liabilities to tangible net worth ratio included in one of our supply agreements with a fuel provider. The violation was caused primarily by a significant increase in our pension liability.  Failure to meet this covenant would have required us to provide a one year irrevocable letter of credit for $3.3 million; however, we received a 30 day time extension to March 27, 2009 to meet this covenant ratio. On March 20, 2009, we calculated the covenant ratio, as of February 28, 2009, and are now are in compliance with this covenant. We plan to notify the fuel provider before March 27, 2009 of our compliance.  At this time management does not anticipate any further covenant violations.


Our line of credit contains a similar covenant ratio. The Company is in compliance with all covenants on our line of credit and other fuel supply agreements at December 31, 2008. Management is continuing to take steps to comply with all covenants going forward, but there can be no assurance that further deterioration of the market or the economy will not occur and give rise to a violation.



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

$50,966 

$1,409 

$2,818 

$2,818 

$43,921 

Long-term Debt Interest

55,923 

3,736 

7,061 

6,512 

38,614 

Natural Gas and Propane Gas Purchase Obligations

48,635 

31,070 

9,753 

5,311 

2,501 

Electric Purchase Obligations

5,170 

574 

1,149 

1,149 

2,298 

Other Purchase Obligations

972 

863 

105 

Pension Plan Contributions

17,757 

1,790 

8,250 

4,655 

3,062 

Total

$179,423 

$39,442 

$29,136 

$20,449 

$90,396 


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.


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

The Company’s contracts for the supply of electricity in our Northeast division effective January 1, 2007 and our Northwest division effective in January 1, 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 minimum pension funding requirements under ERISA and will continue to do so with contributions required during 2009. Current projections indicate that we will make required contributions in 2009 of $560,000 for our 2008 plan year and $1.2 million for our 2009 plan year.  We also intend to make voluntary contributions in 2009 of approximately $4.1 million for our 2008 plan year as summarized in Note 13A in the Notes to Consolidated Financial Statements.  These voluntary contributions are not included in less than one year column in the Contractual Obligations table. We will continue to make future contributions as required by the Pension Protection Act to satisfy minimum funding rules and to avoid any pension plan restrictions.


In an effort to reduce the anticipated expenses and pension liability, the Company is proposing to freeze the pension plan effective December 31, 2009 for all employees currently in the Company’s pension plan. The freeze will reduce both pension expenses and pension contribution beginning in 2010. The freeze will stop additional benefits from accruing in the future, including freezing salary rates at levels existing in 2009. With the freeze, total pension expense and total pension contributions for the next five years are expected to be approximately $1 million and $12 million, respectively.

Environmental cleanup is anticipated to require approximately $774,000 in 2009, 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 13A 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. However, 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, debt covenants 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, 2008, approximately $10.2 million of retained earnings were free of such restriction and available for the payment of dividends.


Line of Credit

We have a revolving line of credit with Bank of America which expires July 1, 2010.  Prior to March 2008, the line of credit was for an available line of $15 million with the ability to increase the limit to a maximum of $20 million upon 30 days notice. In March 2008, we amended our line of credit to allow us, upon 30 days notice, to increase our maximum credit line from $20 million to $26 million and to reduce the interest rate paid on borrowings by 0.10% or 10 basis points. In April 2008, we increased the currently available line of credit from $12 million to $15 million and at December 31, 2008, the balance outstanding was $12.7 million. We reserve $1 million of the line of credit to cover potential expenses for any major storm repairs in our electric segment and an additional $250,000 for a letter of credit insuring propane gas facilities.


Other


Impact of Recent Accounting Standards


Financial Accounting Standard No. 157

In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) 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. 157-2, “Effective Date of FASB Statement No. 157” which deferred 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 has adopted SFAS No. 157 effective January 1, 2008 for financial assets and financial liabilities and effective January 1, 2009 for nonfinancial assets and nonfinancial liabilities. This statement did not have a material impact on our financial condition or results of operation.


Financial Accounting Standard No. 159

In February 2007, the FASB issued 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. We did not elect to report any additional assets or liabilities at fair value and accordingly, the adoption of SFAS 159 did not have a material effect on our financial position or results of operations.


Financial Accounting Standard No. 160

In December 2007, the FASB issued SFAS 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.


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.


Financial Accounting Standard No. 161

In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”. This standard requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.   The Company expects to adopt SFAS No. 161 effective January 1, 2009. The Company does not anticipate the adoption of this standard will have a material effect on our disclosures.


FASB Staff Position, FAS No. 142-3

In April 2008, the FASB issued FASB Staff Position, or “FSP”, FAS 142-3, “Determination of the Useful Life of Intangible Assets,” effective for financial statements issued for fiscal year beginning after December 15, 2008, and interim periods within those fiscal years. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142 “Goodwill and Other Intangible Assets,” thereby resulting in improved consistency between the useful life applied under SFAS No. 142, and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, “Business Combinations.” We will adopt FSP FAS 142-3 effective January 1, 2009. We do not expect that the adoption of FSP, FAS No. 142-3 will have a material effect on our results of operations or financial position.


Financial Accounting Standard No. 162

In May 2008, the FASB issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”.  This standard offers guidance on the principles used to prepare financial statements in accordance with GAAP.  FASB Statements of Financial Accounting Concepts now supersede industry practice. The Company does not anticipate the adoption of this standard will have a material effect on our financial position or results of operation.


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 No. 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 No. 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 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 11- "Contingen­cies" in the Notes to Consolidated Financial Statements.  We intend to vigorously defend our rights in this litigation.  We have insurance and rate relief to cover any expected losses or expenses. We believe that the aggregate of all future contamination assessment and remedial costs, legal fees and other related expenses would not exceed the insurance proceeds received and any rate relief granted.  The final 2004 natural gas rate relief granted by the FPSC provided future recovery of $8.9 million for environmental liabilities. The remaining balance to be recovered from customers through future recovery is included on the balance sheet as “Other regulatory assets-environmental”.


Forward-Looking Statements (Cautionary Statement)

This report contains forward-looking statements that are based on current expectations, estimates, forecasts and projections and management’s beliefs and assumptions. Any statements that are not statements of historical fact should be considered forward-looking statements. Forward-looking statements in this report include, but are not limited to those relating to the following expectations:


·

Our consideration of equity or debt financing in 2009 or 2010.

·

Cash requirements will increase significantly in the future due to environmental clean-up costs, sinking fund payments on long-term debt and pension contributions.

·

Cash from operations, coupled with short-term borrowings on our line of credit, will be sufficient to satisfy our operating expenses, normal construction expenditure and dividend payments through 2009.

·

Realization of actual additional revenues from the electric rate proceeding finalized in May 2008 will occur as expected.

·

Finalization and approval of a natural gas base rate increase will occur in the second quarter of 2009 as expected.

·

Impact of the overall economic conditions on our earnings, customer growth rates, unit sales and sales expense.

·

Capital expenditures will be less than originally expected for 2009.

·

Timing and progress of construction on the South Florida operations facility.

·

Timing of closing on land purchase adjacent to our Central Florida operations facility.

·

Increase in medical insurance costs in 2009.

·

Increase in pension liability reserve and contributions to our defined benefit pension plan in 2009 and beyond.

·

Potential violation of our covenants with our bank that provides our line of credit and with our fuel providers.

·

Increase in bad debt expense on our customer accounts receivable.

·

Impact of Energy Efficiency Legislation on our Company and our operating results.

·

Renewal of the Marianna Franchise.

·

Additional annual expenditures relating to storm preparedness.


Forward-looking 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


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" under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". As of December 31, 2008, we had not entered into any hedging activities, and we do not anticipate entering into hedging activities in 2009. Beginning in 2009, we will start pre-buying propane when certain price levels are reached.


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 $12.7 million at the end of December 2008. 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 2012.


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 $5.86 million to $5.83 million.


In 2008, a hypothetical 0.5% (50 basis points) decrease in the long-term interest rate on $50.9 million debt excluding unamortized debt discount would change the fair value from $56.6 million to $59.6 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 $12.7 million on December 31, 2008 and $11.1 million on December 31, 2007.  A hypothetical 1% increase in interest rates would have resulted in a decrease in annual earnings for 2008 by $127,000 and for 2007 by $110,000, 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

 

2008

 

2007

 

2006

Natural gas

  72,624 

64,850 

71,139 

Electric

 

78,655 

 

55,521 

 

48,527 

Propane gas

 

17,269 

 

16,171 

 

15,115 

Total revenues

 

168,548 

 

136,542 

 

134,781 

Cost of Fuel and Other Pass Through Costs

 

117,321 

 

87,821 

 

85,971 

Gross Profit

 

51,227 

 

48,721 

 

48,810 

Operating Expenses

 

 

 

 

 

 

Operation

 

26,115 

 

25,178 

 

24,422 

Maintenance

 

3,737 

 

3,402 

 

3,484 

Depreciation and amortization

 

8,912 

 

8,286 

 

7,742 

Taxes other than income taxes

 

3,354 

 

3,034 

 

2,985 

Total operating expenses

 

42,118 

 

39,900 

 

38,633 

Operating Income

 

9,109 

 

8,821 

 

10,177 

Other Income and (Expense)

 

 

 

 

 

 

Merchandise and service revenue

 

2,595 

 

3,177 

 

4,322 

Merchandise and service expenses

 

(2,329)

 

(2,801)

 

(4,071)

Other income

 

1,045 

 

690 

 

620 

Other expense

 

(315)

 

(19)

 

(33)

Interest expense on long-term debt

 

(3,855)

 

(3,948)

 

(3,949)

Interest expense on short-term borrowings

 

(296)

 

(187)

 

(108)

Interest expense on customer deposits and other

 

(665)

 

(735)

 

(551)

Total other expense – net

 

(3,820)

 

(3,823)

 

(3,770)

Earnings Before Income Taxes

 

  5,289 

 

4,998 

 

6,407 

Income Taxes

 

(1,803)

 

(1,697)

 

(2,238)

Net Income

 

3,486 

 

3,301 

 

4,169 

Preferred Stock Dividends

 

29 

 

29 

 

29 

Earnings for Common Stock

$

3,457 

3,272 

4,140 

Earnings Per Common Share (basic and diluted)

$

.57 

.54 

.69 

Dividends Declared Per Common Share

$

.47 

.45 

.43 

Average Shares Outstanding

 

6,087,441 

 

6,039,767 

 

5,993,589 


See Notes to Consolidated Financial Statements



Statement of Comprehensive Income

Years Ending December 31,

(Dollars in thousands)

 

2008

2007

2006

Net income

$3,486 

$3,301 

$4,169 

Other comprehensive (loss) income:

 

 

 

  Pension and postretirement plans

(2,628)

        306 

(165)

  Income taxes on pension and post retirement

       989 

(115)

        62 

  Other comprehensive (loss) income

 (1,639)

191 

 (103)

Comprehensive income

  $1,847 

$3,492 

$4,066 





CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

 

December 31,

ASSETS

 

2008

 

2007

Utility Plant

 

 

 

 

Natural gas

$

109,507 

104,770 

Electric

 

79,667 

 

76,520 

Propane gas

 

17,267 

 

17,141 

Common

 

4,187 

 

3,953 

Total

 

210,628 

 

202,384 

Less accumulated depreciation

 

68,303 

 

64,012 

Net utility plant

 

142,325 

 

138,372 

 

 

 

 

 

Current Assets

 

 

 

 

Cash

 

2,997 

 

3,478 

Accounts receivable

 

13,973 

 

12,269 

Income taxes receivable

 

    2,211 

 

Notes receivable

 

252 

 

298 

Allowance for uncollectible accounts

 

(455)

 

(326)

Unbilled receivables

 

2,041 

 

1,879 

Inventories (at average or unit cost)

 

3,961 

 

4,251 

Prepaid expenses

 

1,037 

 

861 

Under-recovery of fuel costs

 

756 

 

    Special deposit - fuel contract

 

130 

 

 188 

    Deferred charges – current

 

155 

 

              211 

    Regulatory asset- environmental - current

 

456 

 

456 

    Deferred income taxes – current

 

513 

 

949 

Total current assets

 

28,027 

 

24,514 

 

 

 

 

 

Other Assets

 

 

 

 

Regulatory asset – environmental

 

6,636 

 

7,197 

Regulatory asset – retirement plan

 

9,945 

 

Long-term receivables and other investments

 

5,619 

 

5,622 

    Investments held for environmental costs

 

3,507 

 

3,444 

Special deposit – fuel contract

 

 

   130 

Deferred charges

 

6,409 

 

6,230 

Goodwill

 

2,405 

 

2,405 

Intangible assets (net)

 

4,058 

 

4,430 

Total other assets

 

38,579 

 

29,458 

Total

$

208,931 

192,344 


  See Notes to Consolidated Financial Statements




CONSOLIDATED BALANCE SHEETS (continued)

(Dollars in thousands)    

 

 

December 31,

CAPITALIZATION AND LIABILITIES

 

2008

 

2007

Capitalization

 

 

 

 

Common shareholders' equity

$

48,512 

48,946 

Preferred stock

 

600 

 

600 

Long-term debt

 

47,920 

 

49,363 

Total capitalization

 

97,032 

 

98,909 

 

 

 

 

 

Current Liabilities

 

 

 

 

Line of credit

 

12,747 

 

11,122 

Accounts payable

 

11,481 

 

9,901 

Long term debt - current

 

1,409 

 

1,409 

Insurance accrued

 

265 

 

218 

Interest accrued

 

1,081 

 

1,163 

Other accruals and payables

 

3,241 

 

2,729 

Environmental liability - current

 

774 

 

1,379 

Taxes accrued

 

1,902 

 

2,168 

Over-earnings liability

 

 

26 

Over-recovery of fuel costs

 

1,608 

 

2,761 

Over-recovery of conservation

 

357 

 

446 

Customer deposits

 

11,099 

 

10,547 

Total current liabilities

 

45,964 

 

43,869 

 

 

 

 

 

Other Liabilities

 

 

 

 

Deferred income taxes

 

17,820 

 

16,630 

Unamortized investment tax credits

 

203 

 

266 

Environmental liability

 

12,655 

 

12,250 

Regulatory liability – cost of removal

 

10,304 

 

9,359 

Regulatory liability - taxes

 

707 

 

796 

Regulatory liability – retirement plan

 

 

564 

Long-term medical and pension reserve

 

19,352 

 

4,817 

Customer advances for construction

 

2,476 

 

2,497 

Regulatory liability – storm reserve

 

2,418 

 

2,387 

Total other liabilities

 

65,935 

 

49,566 

Total

$

208,931 

192,344 


See Notes to Consolidated Financial Statements

 

 

 

 





CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in thousands except per share amounts)


 

December 31,

 

 

2008

 

2007

Common Shareholders' Equity

 

 

 

 

Common stock, $1.50 par value, authorized 10,000,000 shares; issued 6,199,070 shares in 2008; issued 6,182,983 shares in 2007

$

9,299 

9,275 

Paid-in capital

 

6,065 

 

6,076 

Retained earnings

 

36,424 

 

35,797 

Accumulated other comprehensive income/(loss), retirement plan adjustment, net of income tax of $936 in 2008 and $53 in 2007

 

(1,551)

 

88 

Treasury stock - at cost (97,350 shares in 2008, 129,223 shares in 2007)

 

(1,725)

 

(2,290)

Total common shareholders' equity

 

48,512 

 

48,946 

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

 

8,182 

 

9,091 

10.03 % due 2018

 

4,500 

 

5,000 

9.08 % due 2022

 

8,000 

 

8,000 

4.90 % due 2031

 

13,900 

 

14,000 

                 6.85 % due 2031

 

14,975 

 

14,990 

                 Unamortized debt discount

 

(1,637)

 

(1,718)

Total long-term debt

 

47,920 

 

49,363 

Total Capitalization

$

97,032 

98,909 


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 Income/(Loss)

 

Treasury Shares

 

Treasury Shares Cost

Common Shareholders’ Equity

Balances as of December 31, 2005

6,152,676 

 

$9,229 

 

$5,998 

 

$33,625 

 

$        - 

 

188,994

 

$(3,349) 

$45,503 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

4,169 

 

 

 

4,169 

Accumulated other comprehensive loss, retirement plans adjustment, net of income tax  of $62

-

 

-

 

-

 

-

 

(103)

 

 

(103)

Dividends

 

 

 

(2,581)

 

 

 

(2,581)

Stock plans

13,972 

 

21 

 

56 

 

 

 

(28,645) 

 

         507

            584 

Balances as of December 31, 2006

6,166,648 

 

9,250 

 

6,054 

 

35,213 

 

(103)

 

160,349

 

(2,842)

  47,572 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

3,301 

 

 

 

3,301 

Accumulated other comprehensive income, retirement plans adjustment, net of income tax of $115

-

 

-

 

-

 

-

 

                191

 

 

             191 

Dividends

 

 

 

(2,717)

 

 

 

  (2,717)

Stock plans

16,335 

 

25 

 

          22 

 

 

 

(31,126) 

 

         552

             599 

Balances as of December 31, 2007

6,182,983 

 

9,275 

 

     6,076 

 

35,797 

 

                 88

 

129,223

 

 (2,290)

        48,946 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

3,486 

 

 

 

          3,486 

Accumulated other comprehensive loss, retirement plans adjustment, net of income tax of $989

 

 

 

 

(1,639)

 

 

(1,639)

Dividends

 

 

 

(2,859)

 

 

 

   (2,859)

Stock plans

16,087 

 

24 

 

(11) 

 

 

 

(31,873) 

 

         565

             578 

Balances as of December 31, 2008

6,199,070 

 

$9,299 

 

  $6,065 

 

$36,424 

 

$(1,551)

 

97,350

 

$(1,725)

      $48,512 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


See Notes to Consolidated Financial Statements



CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

 

 

Years Ended December 31,

 

 

2008

 

2007

 

2006

Cash Flows from Operating Activities:

 

 

 

 

 

 

Net income

$

3,486 

3,301 

4,169 

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

 

 

 

 

 

 

Depreciation and amortization

 

8,912 

 

8,286 

 

7,742 

Deferred income taxes

 

2,526 

 

(1,198)

 

(2,003)

Bad debt expense

 

831 

 

448 

 

623 

Investment tax credits

 

(63)

 

(69)

 

(75)

Other

 

708 

 

886 

 

805 

Interest income from sale of non-utility property

 

(244)

 

(253)

 

(252)

Compensation expense from the issuance of stock

 

57 

 

47 

 

88 

Effects of changes in:

 

 

 

 

 

 

Receivables

 

(2,836)

 

(620)

 

3,115 

Unbilled receivables

 

(162)

 

78 

 

(39)

Inventories and prepayments

 

(1,667)

 

68 

 

711 

Accounts payable and accruals

 

3,105 

 

4,826 

 

(976)

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

 

(1,998)

 

58 

 

6,500 

Area expansion program deferred costs

 

104 

 

(313)

 

238 

Regulatory asset and environmental liability

 

560 

 

175 

 

584 

Other

 

(699)

 

(1,194)

 

(1,140)

     Net cash provided by operating activities

 

12,620 

 

14,526 

 

20,090 

Cash Flows from Investing Activities:

 

 

 

 

 

 

Construction expenditures

 

(11,227)

 

(16,740)

 

(13,116)

Customer advances received for construction

 

(21)

 

(210)

 

361 

Purchase of long-term investments

 

(62)

 

(80)

 

(106)

Proceeds received on notes receivable

 

283 

 

371 

 

321 

      Other

 

10 

 

 

(15)

     Net cash used in investing activities

 

(11,017)

 

(16,659)

 

(12,555)

Cash Flows from Financing Activities:

 

 

 

 

 

 

Net change in short-term borrowings

 

1,625 

 

7,656 

 

(6,092)

Net change in long-term borrowings

 

(1,442)

 

 

Proceeds from common stock plans

 

521 

 

552 

 

497 

Dividends paid

 

(2,788)

 

(2,681)

 

(2,551)

     Net cash (used in) provided by financing activities

 

(2,084)

 

5,527 

 

(8,146)

Net (Decrease) Increase in Cash

 

(481)

 

3,394 

 

(611)

Cash at Beginning of Year

 

3,478 

 

84 

 

695 

Cash at End of Year

$

2,997 

3,478 

84 

Supplemental Cash Flow Information

 

 

 

 

 

 

Cash was paid during the years as follows:

 

 

 

 

 

 

     Interest

$

4,777 

4,375 

4,777 

     Income taxes

$

2,359 

1,984 

3,298 



See Notes to Consolidated Financial Statements



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.

Summary of Significant Accounting and Reporting Policies


A.

General

Florida Public Utilities Company (FPUC or 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 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 2008 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)

 

2008 

2007 

Assets

 

 

Deferred development costs  (1)

$  4,161 

$  4,265 

Unamortized fuel related regulatory costs (5)

24 

36 

Environmental assets (2)

7,092 

7,653 

Deferred retirement plan costs (4)

9,945 

Unamortized Rate Case expense (7)

861 

535 

Under-recovery of fuel costs (6)

756 

Unamortized piping and conversion costs   (1)

1,273 

1,379 

Unamortized loss on reacquired debt   (1)

172 

190 

Total Regulatory Assets

  $24,284 

  $14,058 

  

 

 

Liabilities

 

 

Tax liabilities (8)

$     707 

$     796 

Cost of removal (9)

10,304 

9,359 

Deferred retirement plan costs  (4)

564 

Storm reserve liabilities(3)

2,418 

2,387 

Over-recovery of fuel costs (6)

1,608 

2,761 

Over-recovery of conservation (6)

357 

446 

Over-earnings liability (3)

26 

Total Regulatory Liabilities

   $15,394 

  $16,339 


(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 in 2008 of our 2006 natural gas over-earnings to additionally fund our storm reserve for our natural gas operations. Our natural gas storm reserve is approximately $790,000 as of December 31, 2008. Our electric storm reserve is approximately $1,629,000 as of December 31, 2008.

(4)

The actuarial valuation of the retirement plan obligations has been completed and the recognition provisions of Statement 158 resulted in a regulatory liability for $564,000 at December 31, 2007 and a regulatory asset for $9.9 million at December 31, 2008.

(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 rate proceedings before the FPSC. These costs are amortized over a four year period. This represents the unamortized portion of these costs. The Company has incurred rate case costs associated with the recent electric filing finalized in 2008 and the natural gas filing expected to be finalized in 2009. Amortization will not begin on the natural gas proceeding until mid 2009.

(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 natural gas segment. Approval of interim rate relief of $1.0 million was granted effective for meter readings on or after March 12, 2009 and final approval, if any, is expected in the second quarter of 2009.


At December 31, 2008, 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 No. 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 No. 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 purchase" 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.


Electric interim rate relief for partial recovery of the increased expenditures was approved by the FPSC on October 23, 2007. Interim rates were effective November 2007. A final annual electric rate increase of approximately $3.9 million a year was approved in April 2008, with the new rates which began on May 22, 2008.  These revenues provided an increase to our overall profitability for the electric segment and recovery of increased expenditures including depreciation, storm readiness mandates and initiatives and other expenses incurred throughout 2008.


We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase in our natural gas segment. This request included recovery of increased expenses and some capital expenditures since our last rate proceeding in 2004. Finalization of this request and approval, if any, of a natural gas base rate increase would not occur until mid 2009. Interim rates which will produce additional annual revenues of approximately $1 million went into effect for meter readings on and after March 12, 2009. These interim revenues are collected subject to refund pending the outcome of our final rate increase.


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, 2008 and 2007 was $8.7 million and $7.1 million, respectively.


I.

Allowance for Doubtful Accounts

The Company records an allowance 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.


Our accounts receivable are considered delinquent after 21 days. The customer receives a delinquent notice reminder to pay within 5 days.  If payment is not received by the date specified on the delinquent notice, we send a collector out to either collect the past due amount or disconnect the account for nonpayment.  We provide for a bad debt provision for all accounts over 90 days unless special circumstances exist.  We also provide for a bad debt provision based on historical data for those accounts less than 90 days. All accounts are generally written off after 90 days and sent to an outside, third party collection agency.

 

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

2006

$ 272

466

623

$ 429

2007

$ 429

551

448

$ 326

2008

$ 326

702

831

$ 455

 

A large industrial customer in our Northeast electric division filed for bankruptcy on January 26, 2009. This customer has currently paid for all outstanding receivable amounts as of December 31, 2008 and accordingly, there has been no provision for bad debt allowances as of December 31, 2008 for this customer.

J.

Utility Plant and Depreciation

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


Utility Plant

(Dollars in thousands)

Plant Classification

Annual Composite Depreciation Rate

2008 

2007 

Land

 

$      4,545 

$      4,537 

Buildings

2.0% to 4.9%

7,647 

7,085 

Distribution

1.8% to 7.5%

174,810 

167,327 

Transmission

1.8% to 3.8%

6,970 

6,957 

Equipment

2.2% to 20.0%

14,190 

13,307 

Furniture and Fixtures

4.8% to 20.0%

444 

417 

Work-in-Progress

 

2,022 

2,754 

 

 

$ 210,628 

$ 202,384 


Depreciation for the Company’s regulated segments is computed using the composite straight-line method at rates prescribed by the FPSC for financial accounting purposes.  Propane gas depreciation is computed using a composite straight-line method at an average rate based on estimated average life of approximately 20-30 years.  Such rates are based on estimated service lives of the various classes of property.  Depreciation provisions on average depreciable property approximate 3.9% in 2008, 3.8% in 2007 and 3.9% in 2006. Depreciation expense was $7.3 million, $6.7 million and $6.2 million for 2008, 2007 and 2006, respectively.


K.

Earnings Per Share

The Company includes earnings per common share (basic and diluted) on the consolidated statements of income. The Company does not have any outstanding stock based awards that would be dilutive or anti-dilutive.


L.

Impact of Recent Accounting Standards

Financial Accounting Standard No. 157


In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) 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. 157-2, “Effective Date of FASB Statement No. 157” which deferred 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 has adopted SFAS No. 157 effective January 1, 2008 for financial assets and liabilities and effective January 1, 2009 for nonfinancial assets and nonfinancial liabilities. This statement did not have a material impact on our financial condition or results of operation.


Financial Accounting Standard No. 159

In February 2007, the FASB issued 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. We did not elect to report any additional assets or liabilities at fair value and accordingly, the adoption of SFAS 159 did not have a material effect on our  on our financial position or results of operations.


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.


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 from the business combination.  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.


Financial Accounting Standard No. 161

In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”. This standard requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.   The Company expects to adopt SFAS No. 161 effective January 1, 2009. The Company does not anticipate the adoption of this standard will have a material effect on our disclosures.


FASB Staff Position, FAS No. 142-3

In April 2008, the FASB issued FASB Staff Position, or “FSP”, FAS 142-3, “Determination of the Useful Life of Intangible Assets,” effective for financial statements issued for fiscal year beginning after December 15, 2008, and interim periods within those fiscal years. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142 “Goodwill and Other Intangible Assets,” thereby resulting in improved consistency between the useful life applied under SFAS No. 142, and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, “Business Combinations.” We will adopt FSP FAS 142-3 effective January 1, 2009. We do not expect that the adoption of FSP, FAS No. 142-3 will have a material effect on our results of operations or financial position.


Financial Accounting Standard No. 162

In May 2008, the FASB issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”.  This standard offers guidance on the principles used to prepare financial statements in accordance with GAAP.  FASB Statements of Financial Accounting Concepts now supersede industry practice. The Company does not anticipate the adoption of this standard will have a material effect on our financial position or results of operation.


M. Advertising Expense

                                                                                                                                                                                                                     The Company follows the accounting policy of expensing advertising costs as they are incurred.  The amounts recognized for advertising expenses were $249,000 and $308,000 in 2008 and 2007, respectively.


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 at least annually, or periodically, if events or circumstances may indicate possible impairment tests the goodwill and indefinite lived intangibles for impairment by reporting segment. In the event impairment exists, the Company would write-down the associated goodwill and intangible assets with indefinite lives to fair value. The impairment tests performed in 2007 and 2008 resulted in no impairment charges.


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 $550,000 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)

 

 

2008 

2007 

Customer distribution rights

(Indefinite life)

$ 2,800 

$ 2,800 

Software

(Five to nine year life)

3,542 

3,499 

Accumulated amortization

(2,284)

(1,869)

Total intangible assets, net of amortization

$4,058 

$ 4,430 


The 2008 amortization expense of computer software was approximately $424,000. The Company expects the amortization expense of computer software to be approximately $400,000 annually over the next five years, with the current level of software investment.


3.

Notes Receivables


As of December 31, 2008 there was approximately $5.9 million in receivables from the 2003 sale of our water assets with the interest of 4.34%. We received an installment of $252,000 in February of 2009.  Final payment of principal and interest totaling $5.8 million is expected in February 2010.  


4.

Over-earnings - Natural Gas


The FPSC approves rates that are intended to permit a specified rate of return on investment and limits the maximum amount of earnings of regulated operations. The Company has agreed with the FPSC staff to limit the earned return on equity for regulated natural gas and electric operations. The table below summarizes our overearnings activities for the years ending 2008, 2007 and 2006.


Natural Gas Over-Earnings Summary

 (Dollars in thousands)

 

Years Ended December 31

 

2008

2007

2006

Revenues:

 

 

 

Revenues excluding over-earnings

      $72,759 

        $64,820 

      $71,160 

   2005 Over-earnings

(16)

   2006 Over-earnings

(135)

                 46 

(21)

Natural Gas Revenue

      $72,624 

       $ 64,850 

      $71,139 

 

 

 

 

Other Income and (Expense):

 

 

 

Interest expense excluding interest on over-earnings

$649 

$658 

$551 

   2005 Over-earnings interest

76 

   2006 Over-earnings interest

16 

Interest expense on customer deposits and other

$      665 

$      735 

$    551 

 

 

 

 

 

As of December 31,

 

 

2008

2007

 

Capitalization and Liabilities:

 

 

 

Beginning Over-earnings liability

             $26 

        $722 

 

   Adjustment for 2005 Over-earnings

                92 

 

   Transfer of 2005 Over-earnings to storm reserve

(610)

 

   Applied 2005 Over-earnings to regulatory asset –        storm reserve

(133)

 

   Adjustment for 2006 Over-earnings

             151 

(45)

 

   Transfer of 2006 Over-earnings to storm reserve

(177)

 

Ending Over-earnings liability

$           - 

$        26 

 


In 2008, there are no estimated natural gas and electric over-earnings.


On September 29, 2008 the FPSC finalized the 2006 over-earnings for the natural gas segment. Total over-earnings was determined to be $160,000, plus interest of $ 17,000. The FPSC ordered the disposition of 2006 over-earnings to provide additional funds for the natural gas storm reserve.


On August 14, 2007 the FPSC 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 FPSC 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.

Storm Reserves


As of December 31, 2008, the Company had a storm reserve of approximately $1.6 million for the electric segment and approximately $790,000 for the natural gas segment. The Company does not have a storm reserve for the propane gas segment.


The FPSC 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 2005 over-earnings and the 2006 over-earnings were used to fund a storm reserve for any future storm costs.


6.

Income Taxes

A.

Provision for Income Taxes

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


(Dollars in thousands)

 

Years ended December 31,

 

 

2008 

 

2007 

 

2006

Current payable:

 

 

 

 

 

 

  Federal

$

(558)

2,518 

3,652 

  State

 

(102)

 

446 

 

664 

    Current

 

(660)

 

2,964 

 

4,316 

Deferred:

 

 

 

 

 

 

  Federal

 

2,152 

 

(1,028)

 

(1,723)

  State

 

374 

 

(170)

 

(280)

     Deferred – net

 

2,526 

 

(1,198)

 

(2,003)

 

 

 

 

 

 

 

Investment tax credit

 

(63)

 

(69)

 

(75)

Total income taxes

$

1,803 

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:


 

Effective Rate Reconciliation

(Dollars in thousands)

Years ended December 31,

 

 

2008

2007 

2006 

Federal income tax at statutory rate (34%)

 

$     1,798 

$       1,699 

$       2,178 

State income tax, net of federal benefit

 

194 

181 

 233 

Investment tax credit

 

(63)

(69)

 (75)

Tax exempt interest

 

(83)

(85)

(85)

Other

 

(43)

(29)

 (13)

Total provision for income taxes

 

$      1,803 

$       1,697 

$       2,238 


C.

Deferred Income Taxes

Tax effect of temporary differences which give rise to deferred taxes assets and deferred tax liabilities are as follows:


(Dollars in thousands)

 

Years ended December 31,

Deferred tax assets:

 

2008

 

2007

   Environmental liability

$

2,384 

2,249 

   Self insurance liability

 

792 

 

763 

   Vacation payable

 

542 

 

384 

   Allowance for doubtful accounts

 

171 

 

123 

   General liability

 

100 

 

82 

   Storm reserve liability

 

910 

 

898 

   Amortizable customer based intangible

 

733 

 

670 

   Pension liability

 

847 

 

1,086 

   Under/over Recoveries – conservation costs

 

134 

 

167 

   Other assets

 

117 

 

57 

Total deferred tax assets

$

6,730 

6,479 


Deferred tax liabilities:

 

 

 

 

   Utility plant related and intangibles

$

 22,790 

 21,458 

   Underrecovery of fuel costs

 

 843 

 

 406 

   Rate case expense

 

324 

 

 201 

   Other liabilities

 

80 

 

 95 

Total deferred tax liabilities

$

24,037 

 22,160 

Net deferred income taxes

$

17,307 

 15,681 


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


(Dollars in thousands)

 

Years ended December 31,

 

 

2008

 

2007

Deferred income tax - long term liabilities

$

 17,820 

 16,630 

  Less:  Deferred income tax - current assets

 

513 

 

949 

Net deferred income tax liabilities

$

17,307 

15,681 


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.


D.

Financial Accounting Standard Board Interpretation No. 48

On January 1, 2007 the Company adopted FIN 48. The interpretation prescribes a more likely-than-not recognition threshold and establishes new measurement requirements for financial statements reporting of an entity’s income tax positions. We have performed an analysis of tax positions taken and expected to be taken on the tax returns and assessed the technical merits of each tax position (by relying on legislation and  statutes, common legislative intent, regulations, rulings, and case law).  We have determined that we have no material uncertain tax positions.


E.

IRS Audits and Income Taxes Receivable

In February 2008, the IRS completed its examination of our 2003 and 2004 federal income tax returns.  We reclassified the tax liability recognized in 2007 related to this audit as a current tax payable.  We paid this tax liability and the interest of approximately $195,000 and $48,000 respectively in July 2008.  This adjustment does not affect our annual effective income tax rate, and did not result in a material change in our financial position.


The Company amended its 2004 Florida corporate income tax returns to reflect the 2004 IRS audit adjustments.


During 2008, the IRS also examined our 2005 and 2006 tax years.  Based on the completion of the IRS examination, at December 31, 2008 we had an income tax receivable of $346,000 and interest income of approximately $45,000 for the 2005 and 2006 tax years. The federal portion of this refund was received in 2009.


Due to the significant increase in our pension liability and in our pension contributions, our income tax for 2008 will be lower than originally estimated.  We paid tax estimates in the first half of 2008 with the expectation of paying pension payments that were consistent with prior years.  The additional tax deduction that will result from the increased pension expense will result in an overpayment of taxes for 2008.  We have filed for a quick refund of that estimate overpayment of approximately $1.9 million which is included in income taxes receivable on the consolidated balance sheets at December 2008. We expect to receive this tax refund in the first half of 2009.


7.

Capitalization


A.

Common Shares Reserved

The Company has 3,800,930 authorized but unissued shares and 97,350 treasury shares as of December 31, 2008. The Company has reserved the following common shares for issuance as of December 31, 2008:




Dividend Reinvestment Plan

21,649

Employee Stock Purchase Plan

121,351

Board Compensation Plan

13,399


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, 2008. 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, 2008, approximately $10.2 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, 2008 the Company was not in violation of these covenants. See Note 14 in Notes to Consolidated Financial Statements.


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.


8.

Long-term Debt


The Company issued its Fourteenth Series of 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.  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 Company’s long-term mortgage bonds are callable only if they are in default or the Company is in violation or the Company wishes to pre-pay the bonds. Although the Company has the option to pre-pay the bonds, the company currently does not plan to do so within the next 12 months.


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 annual sinking fund payments of $909,000 and $500,000 respectively, which began 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 $1.6 million in 2008 and $1.7 million in 2007.


Annual Maturities of Long-Term Debt

(Dollars in thousands)

 

Total

2009

2010

2011

2012

2013

Thereafter

 

 

 

 

 

 

 

 

Long-term Debt

$50,966

$1,409

$1,409

$1,409

$1,409

$1,409

$ 43,921


9.

Line of Credit


In 2004, the Company 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 2008, the agreement was amended with an expiration date of July 1, 2010, and a maximum of $26 million. The amendment also reduces the interest rate paid on borrowings by 0.10% or 10 basis points.  Effective April 29, 2008, we increased the available line of credit from $12 million to $15 million, with a current outstanding balance of $12.7 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.


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


Year

Rate

2008

3.5%

2007

6.1%

2006

6.0%


10. Fair Value of Financial Instruments


The carrying amounts reported in the balance sheet for investments held in escrow for environmental costs, notes payable, taxes accrued and other accrued liabilities approximate fair value.  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.


 

2008

2007

(Dollars in thousands)

Carrying Amounts

Approximate Fair Value

Carrying Amounts

Approximate Fair Value

Long-term debt

$ 50,966

$56,600

$ 52,490

$60,000


11. Contingencies


Environmental



The Company is subject to federal and state legislation with respect to soil, groundwater and employee health and safety matters and to environmental regulations issued by the Florida Department of Environmental Protection, the United States Environmental Protection Agency 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

$      5,100

$   18,300

Sanford

645

645

Pensacola and Key West

120

120

Total

$      5,865

 $   19,065


The Company currently has $13.4 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.  On October 18, 2004 the FPSC approved recovery of $9.1 million for environmental liabilities from rates.  The Company has recovered a total of $6.3 million from insurance and rate recovery, net of costs incurred to date.  The remaining balance of $7.1 million is recorded as a regulatory asset.  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 us in West Palm Beach, Florida upon which we previously operated a gasification plant. Pursuant to a Consent Order between the Company and the Florida Department of Environmental Protection effective April 8, 1991, the Company completed the delineation of soil and groundwater impacts at the site. On June 30, 2008, the Company transmitted a revised feasibility study, evaluating appropriate remedies for the site, to the Florida Department of Environmental Protection.


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


Negotiations between the Company and the Florida Department of Environmental Protection on a final remedy for the site continue. Prior to the conclusion of those negotiations, we are unable to determine, to a reasonable degree of certainty, the complete extent or cost of remedial action that may be required. As of December 31, 2008, and subject to the limitations described above, the Company's remediation expenses, including attorneys' fees and costs, are projected to range from approximately $5.1 million to $18.3 million for this site.

Sanford Site

The Company owns a parcel of property located in Sanford, Florida, upon which a gasification plant was operated prior to our acquisition of the property. On March 25, 1998, the Company executed an Administrative Order on Consent with the four former owners and operators (collectively, the "Group") and the United States Environmental Protection Agency that obligated the Group to implement a Remedial Investigation/Feasibility Study and to pay the United States Environmental Protection Agency's past and future oversight costs. The Group also entered into a Participation Agreement and an Escrow Agreement on or about April 13, 1998. Work under the Remedial Investigation/Feasibility Study Administrative Order on Consent and Participation Agreement and an Escrow Agreement is now complete and the Company has no further obligations under either document.

In 2008, a revised Consent Decree was signed by all Group Members and the United States Environmental Protection Agency, providing for the implementation by the Group of the remedies the United States Environmental Protection Agency approved earlier for the site, which are set forth in the Records of Decision for Operable Units 1-3, and for the payment of the United States Environmental Protection Agency's past and future oversight costs. The Consent Decree was entered by the federal Court in Orlando and became effective on January 15, 2009; the parties to the Consent Decree are now obligated to implement the remedy approved by United States Environmental Protection Agency for the site.


In January 2007, the Company and other members of the Group signed a Third Participation Agreement, which provides for funding the remediation work specified in the Records of Decision for Operable Units 1-3 and supersedes and replaces the Second Participation Agreement.  The Company's share of remediation costs under the Third Participation Agreement is set at 5% of a maximum of $13 million, or $650,000. To date, the Company has contributed $100,000 of its total share of remediation costs under the Third Participation Agreement. It is currently anticipated that the total cost of the final remedy will exceed $13 million. The Company has advised the other members of the Sanford Group that we are unwilling at this time to agree to pay any sum in excess of the $650,000 committed by us in the Third Participation Agreement.

 

Several members of the Sanford Group recently concluded negotiations with two adjacent property owners to resolve damages that the property owners allege that they have/will incur as a result of the implementation of the EPA approved remedy. In settlement of these claims, members of the Sanford Group (excluding the Company) have agreed to pay specified sums of money to the parties. In one case, the settlement agreement requires the select members of the Sanford Group to purchase the third party's property for approximately $2 million; the third party then has an option to buy back the property after completion of the remedy for approximately the same amount. In the other case, the select members agreed to a lump sum payment of $428,000. The Company has refused to participate in the funding of the third party settlement agreements based on the contention that it did not contribute to the release of hazardous substances at the site giving rise to the third party claims.

As of December 31, 2008, the Company’s share of remediation expenses, plus the Company’s attorneys' fees and costs, are projected to be approximately $645,000 for this site. However, at this time, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept the Company’s asserted defense to liability for costs exceeding $13 million to implement the final remedy for the site or will pursue a claim against the Company for a sum in excess of the $650,000 that FPUC has committed to fund the remedy. Accordingly, we are unable to conclude that the likelihood of an adverse outcome is probable or remote.


Pensacola Site

The Company is the prior owner/operator of the former Pensacola gasification plant, located at the intersection of Cervantes Street and the Louisville and Nashville (CSX) Railroad line, Pensacola, Florida. Following notification on October 5, 1990, that the Florida Department of Environmental Protection had determined that the Company was one of several responsible parties for any environmental impacts associated with the former gasification plant site, the Company entered into cost sharing agreements with three other responsible parties providing for the funding of certain contamination assessment activities at the site.


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


In March 1999, the United States Environmental Protection Agency requested site access in order to undertake an Expanded Site Inspection. The Expanded Site Inspection was completed by the United States Environmental Protection Agency's contractor in 1999 and an Expanded Site Inspection Report was transmitted to the Company in January 2000. The Expanded Site Inspection Report recommends additional work at the site. The responsible parties met with the Florida Department of Environmental Protection on February 7, 2000 to discuss the United States Environmental Protection Agency's plans for the site. In February 2000, the United States Environmental Protection Agency indicated preliminarily that it will defer management of the site to the Florida Department of Environmental Protection; as of July 31, 2008, the Company has not received any written confirmation from the United States Environmental Protection Agency or the Florida Department of Environmental Protection regarding this matter. Prior to receipt of the United States Environmental Protection Agency's written determination regarding site management, we are unable to determine whether additional field work or site remediation will be required by the United States Environmental Protection Agency and, if so, the scope or costs of such work.


As of December 31, 2008, the Company’s share of remediation expenses for the site, including attorney’s fees and costs, are projected to be approximately $27,000.


Key West Site

Between 1927 and 1938, the Company owned and operated a gasification plant on Catherine Street, 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 was prepared by a consultant jointly retained by the Company and the current site owner and was delivered to the Florida Department of Environmental Protection. The Preliminary Contamination Assessment Report reported that very limited soil and groundwater impacts were present at the site. By letter dated December 20, 1993, the Florida Department of Environmental Protection notified the Company that the site did not warrant further "CERCLA consideration and a Site Evaluation Accomplished disposition is recommended." the Florida Department of Environmental Protection then referred the matter to its Marathon office for consideration of whether additional work would be required by the Florida Department of Environmental Protection's district office under Florida law. As of December 31, 2008, the Company has received no further communication from the Florida Department of Environmental Protection with respect to the site. At this time, we are unable to determine whether additional field work will be required by the Florida Department of Environmental Protection and, if so, the scope or costs of such work. In 1999, the Company received an estimate from its consultant that additional costs to assess and remediate the reported impacts would be approximately $166,000. As of December 31, 2008 and assuming the current owner shared in such costs according to the allocation agreed upon by the parties for the Preliminary Contamination Assessment Report, the Company's share of remediation expenses, including attorneys' fees and costs, is projected to be $93,000 for this site.

12.  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, 2008, the Company had 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 $31.1 million during 2009 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.


13.

Employee Benefit Plans


A.

Pension Plan

The Company sponsors a qualified defined benefit pension plan for non-union employees that were hired before January 1, 2005 and for unionized employees that work under one of the six Company union contracts and were hired before their respective contract dates in 2005 and 2006.  


In an effort to reduce the anticipated expenses and pension liability, the Company is proposing to freeze the pension plan effective December 31, 2009 for all employees currently in the Company’s pension plan. The freeze will reduce both pension expenses and pension contribution beginning in 2010. The freeze will stop additional benefits from accruing in the future, including freezing salary rates at levels existing in 2009. With the freeze, total pension expense and total pension contributions for the next five years are expected to be approximately $1 million and $12 million, respectively.


Our Company adopted the recognition provisions of SFAS No. 158, as required, at December 31, 2006 and used December 31 as the measurement date to measure the assets and obligations of our 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. As an offset, the regulatory portion of this liability has been deferred as a regulatory asset to be recovered in future periods and the remaining loss has been included in other accumulated comprehensive income (loss) net of taxes.


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


The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets over the three year period ending December 31, 2008 and a statement of the funded status as of December 31, of all three years:





 

Benefit Obligations and Funded Status

 

 

Fiscal Year Ending December 31,

 

 

2008

2007

2006

Accumulated Benefit Obligation at the End of the Year

$37,441,162 

$34,139,719 

$33,693,860 

 

 

 

 

Change in Projected Benefit Obligation on a Measurement Year Basis:

 

 

 

 

Projected Benefit Obligation at the Beginning of the Period

 39,519,824 

   38,650,888 

   36,349,925 

 

Service Cost

 1,014,581 

  1,053,824 

  1,225,495 

 

Interest Cost

 2,582,227 

 2,293,540 

 2,160,719 

 

Actuarial (Gain) or Loss

 1,553,709 

 (909,856)

   541,865 

 

Benefits Paid

 (1,603,717)

    (1,568,572)

    (1,529,258)

 

Curtailment

  - 

  - 

 (97,858)

 

Projected Benefit Obligation at the End of the Period

$43,066,624 

$39,519,824 

$38,650,888 

 

 

 

 

Change in Plan Assets on a Measurement Year Basis:

 

 

 

 

Fair Value of Plan Assets at the Beginning of the Period

 $36,240,316 

 $35,635,214 

 $32,936,666 

 

Actual Return on Plan Assets

  (9,726,707)

    1,923,674 

  3,977,806 

 

Benefits Paid

  (1,603,717)

    (1,568,572)

    (1,529,258)

 

Employer Contributions

     400,000 

      250,000 

      250,000 

 

Fair Value of Assets at the End of the Period

$25,309,892 

$36,240,316 

$35,635,214 

 

 

 

 

Funded Status at the End of the Measurement Year:

$(17,756,732)

$(3,279,508)

$(3,015,674)

 

 

 

 

 

Amounts Recognized in the Statement of Financial Position At Year-End after Applying FAS 158:

 

 

 

 

  Portion of Amount Recognized as Accumulated Other  

  Comprehensive (Income) Loss

 $2,590,973 

 $(29,768)

               $207,885 

 

  Portion of Amount Recognized as Regulatory Asset    (Liability) –retirement plans

 10,363,894 

 (156,979)

 737,049 

 

Net Amount Recognized at Year-End

$12,954,867

    $(186,747) 

     $944,934

 

 

 

 

Amounts Recognized in Accumulated Other Comprehensive (Income) Loss and Regulatory Asset (Liability) after Applying FAS 158:

 

 

 

 

Transition Obligation (Asset)

$                  - 

$                 - 

$                 - 

 

Prior Service Cost (Credit)

  2,535,898 

 3,255,374 

 3,992,489 

 

Net (Gain) or Loss

 10,418,969 

 (3,442,121)

 (3,047,555)

 

Net Amount Recognized at the End of the Year (Note 13. C.)

$12,954,867 

$(186,747)

$944,934 

 

 

 

 

Weighted Average Assumptions at the End of the Year

 

 

 

 

Discount Rate

6.35%

6.65%

6.00%

 

Rate of Compensation Increase

3.75%

3.90%

3.25%

 

Mortality

RP-2000

RP-2000

GAM 83



The following table provides the components of net periodic benefit cost for the plans for fiscal years 2008, 2007 and 2006:



Net Periodic Pension Cost

 

 

 

Years Ended December 31,

 

 

 

2008

2007

2006

(1)

Service Cost

$1,014,581 

$1,053,824 

$1,225,495 

(2)

Interest Cost

2,582,227 

2,293,540 

2,160,719 

(3)

Expected Return on Plan Assets

(2,580,674)

(2,438,964)

(2,426,064)

(4)

Amortization of Transition Obligation/(Asset)

(5)

Amortization of Prior Service Cost

719,476 

737,115 

737,115 

(6)

Amortization of Net (Gain)

(7)

Total FAS 87 Net Periodic Pension Cost

$1,735,610 

$1,645,515 

$1,697,265 

(8)

FAS 88 Charges / (Credits)

 

 

 

 

(a)

Curtailment

(97,858)

(9)

Total Net Periodic Pension Cost

$1,735,610 

$1,645,515 

$1,599,407 

(10)

Weighted Average Assumptions

 

 

 

 

(a)

Discount Rate at Beginning of the Period

6.65%

6.00%

5.90%

 

(b)

Expected Return on Plan Assets

8.50%

8.50%

8.50%

 

(c)

Rate of Compensation Increase

3.90%

3.25%

3.15%



Expected Amortizations

 

 

 

Fiscal Year Ending December 31,

 

 

 

2009

 

2008

 

2007

(1)

Expected Amortization of Transition Obligation (Asset)

$             -

 

$             -

 

$             -

(2)

Expected Amortization of Prior Service Cost (Credit)

684,830

 

719,476

 

737,115

(3)

Expected Amortization of Net Loss (Gain)

$140,000

 

$             -

 

$             -



Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2009

2008

2007

2006

(1)

Plan Assets

 

 

 

 

 

(a)

Equity Securities

40% - 75%

69%

64%

68%

 

(b)

Debt Securities

25% - 50%

30%

36%

30%

 

(c)

Real Estate

0% - 0%

0%

0%

0%

 

(d)

Other

  0% - 15%

1%

0%

2%

 

(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. As a guideline, no more than 10% of the portfolio is invested in any one issue.


Cash Flows

 

 

 

 

 

 

 

(1)

Expected Contributions for Fiscal Year Ending December 31, 2009

 

 

Required Minimum Employer Contributions for 2008 plan year

 

$    560,000

 

 

Voluntary Employer Contributions for 2008 plan year

 

4,065,000

 

 

Total Employer Contributions in 2009 for 2008 plan year

 

4,625,000

 

 

Required Minimum Payments for 2009 plan year

 

1,230,000

 

 

Expected Employer Contributions in 2009

 

$5,855,000 

 

 

Expected Employee Contributions

 

-

(2)

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

 

 

2009

 

 

 

 $2,007,172

 

 

2010

 

 

 

 $2,130,588

 

 

2011

 

 

 

 $2,229,920

 

 

2012

 

 

 

 $2,373,239

 

 

2013

 

 

 

 $2,550,996

 

 

2014 – 2018

 

 

 $15,225,040

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/09

-



Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

(1)

Market-Related Value of Assets as of beginning of fiscal year

$31,152,347

 

$29,485,534

 

$29,290,131

(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

10.3

 

10.56

 

10.8

(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

12/31/2008

 

12/31/2007

 

12/31/2006



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, 2008:


 

 

Benefit Obligations and Funded Status

 

 

Fiscal Year Ending December 31,

 

 

 

2008

2007

2006

Change in Accumulated Postretirement Benefit Obligation on a Measurement Year Basis:

 

 

 

 

 

Accumulated Postretirement Benefit Obligation at the Beginning of the Period

$1,621,553 

 $1,865,353 

$ 2,343,583 

 

 

Service Cost

 52,592 

 54,603 

 59,982 

 

 

Interest Cost

 103,917 

 95,348 

 105,483 

 

 

Actuarial (Gain) or Loss

 (13,642)

 (329,969)

 (568,755)

 

 

Benefits Paid

 (105,953)

 (96,975)

(117,459)

 

 

Change in Plan Provisions

    - 

   - 

   - 

 

 

Plan Participant Contributions

 34,740 

 33,193 

  42,519 

 

 

Accumulated Postretirement Benefit Obligation at the End of the Period

 $1,693,207 

 $1,621,553 

 $1,865,353 

Change in Plan Assets on a Measurement Year Basis:

 

 

 

 

 

Fair Value of Plan Assets at the Beginning of the Period

$               - 

$                - 

$                - 

 

 

Benefits Paid

 (105,953)

 (96,975)

(117,459)

 

 

Employer Contributions

 71,213 

 63,782 

 74,940 

 

 

Plan Participant Contributions

 34,740 

 33,193 

 42,519 

 

 

Fair Value of Assets at the End of the Period

 $               - 

 $                - 

 $                - 

 

 

 

 

Funded Status at the End of the Measurement Year:

$(1,693,207)

$(1,621,553)

$(1,865,353)

 

 

 

 

 

 

Amounts Recognized in the Statement of Financial Position At Year-End After Applying FAS 158

 

 

 

 

 

Net Asset (Liability):  

$(1,693,207)

$(1,621,553)

$(1,865,353)

 

 

  Portion of Amount Recognized as Accumulated Other

  Comprehensive (Income)   

(104,845)

(110,565)

(42,346)

 

 

  Portion of Amount Recognized as Regulatory Asset

  (Liability) -retirement plans   

(419,380)

(406,768)

(150,134)

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

 

 

 

 

 

(Current Liabilities) included in Other Accruals and Payables

 (98,355)

 (88,176)

  (150,589)

 

 

(Noncurrent Liabilities) included in Long-term medical and pension reserve

 (1,594,852)

 (1,533,377)

 (1,714,764)

 

 

Total Net Asset (Liability):

$(1,693,207)

$(1,621,553)

$(1,865,353)

Amounts Recognized in Accumulated Other Comprehensive Income After Applying FAS 158

 

 

 

 

 

Transition Obligation (Asset)

 171,574 

214,470 

 257,366 

 

 

Prior Service Cost (Credit)

      - 

       - 

       - 

 

 

Net (Gain) or Loss

 (695,799)

 (731,803)

 (449,846)

 

 

Net Amount Recognized at the End of the Year (Note 13. C.)

$(524,225)

$(517,333)

$(192,480)

Weighted Average Assumptions at the End of the Year

 

 

 

 

 

Discount Rate

6.60%

6.45%

6.00%

 

 

Rate of Compensation Increase

N/A

N/A

N/A

 

 

Mortality

RP-2000

RP-2000

GAM 83

Assumed Health Care Cost Trend Rates

 

 

 

 

 

Health Care Cost Trend Rate Assumed for Next Year

9.50%

10.50%

11.50%

 

 

Ultimate Rate

5.00%

5.00%

5.00%

 

 

Year that the Ultimate Rate is Reached

2014

2014

2014



Net Periodic Postretirement Benefit Cost

 

 

 

Years ended December 31,

 

 

 

2008

 

2007

 

2006

(1)

Service Cost

$52,592 

 

$54,603 

 

$59,982 

(2)

Interest Cost

103,917 

 

95,348 

 

105,483 

(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

(49,646)

 

(48,012)

 

(17,981)

(6)

Total Net Periodic Benefit Cost

$149,759 

 

$144,835 

 

$190,380 

(7)

Weighted Average Assumptions

 

 

 

 

 

 

(a)

Discount Rate

6.45%

 

6.00%

 

5.90%

 

(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

10.50%

 

11.50%

 

12.50%

 

 

Current Year

 

 

 

 

 

 

(b)

Ultimate Rate

5.00%

 

5.00%

 

5.00%

 

(c)

Year that the Ultimate Rate is Reached

2014

 

2014

 

2014



Expected Amortizations

 

 

 

Years ended December 31,

 

 

 

2009

 

2008

 

2007

(1)

Expected Amortization of Transition Obligation (Asset)

$42,896

 

$42,896

 

$42,896

(2)

Expected Amortization of Prior Service Cost (Credit)

-

 

-

 

-

(3)

Expected Amortization of Net Loss (Gain)

$(49,668)

 

$(49,646)

 

$(48,012)

(4)

Impact of One-Percentage-Point Change in

 

 

 

 

 

 

 

 

 

 

 

 

Sensitivity

(1)

Assumed Health Care Cost Trend Rates

Increase 

 

Decrease 

 

 

 

(a)

Effect on Service Cost + Interest Cost

$21,105

 

($18,078)

 

 

 

(b)

Effect on Postretirement Benefit Obligation

$184,496

 

($160,397)

 

 



Plan Assets

 

 

 

Target

Percentage of Plan

 

 

 

Allocation

Assets at December 31

 

 

 

2009

2008

2007

2006

(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 12/31/2009

 

 

 

(a)

Expected Employer Contributions

 

 

 $98,355

 

(b)

Expected Employee Contributions

 

 

 $36,332

(2)

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

 

 

Total

Medicare Part-D Reimbursement

Employee

Employer

 

(a)

12/31/2009

 $146,143

 $11,456

 $36,332

 $98,355

 

(b)

12/31/2010

 $157,907

 $12,004

 $39,325

 $106,578

 

(c)

12/31/2011

 $169,174

 $12,603

 $39,728

 $116,843

 

(d)

12/31/2012

 $192,641

 $13,099

 $43,581

 $135,961

 

(e)

12/31/2013

 $187,531

 $14,050

 $45,505

 $127,976

 

(f)

12/31/2014 - 12/31/2018

 $1,136,158

 $82,872

 $269,523

 $783,763

 

 

 

 

 

 

 

(3)

Amount of Plan Assets Expected to be Returned to the Employer in the Fiscal Year Ending 12/31/2009

 $ 0





Other Accounting Items

 

 

 

Years Ended December 31,

 

 

 

2008

 

2007

 

2006

(1)

Market-Related Value of Assets as of beginning of year

 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

10.60

 

10.90

 

11.10

(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

12/31/2008

 

12/31/2007

 

12/31/2006


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," Aon’s proprietary prescription drug pricing tool was used. This tool allowed us to determine the estimated Per Member Per Month prescription drug cost for both the company plan and the Medicare plan.  The two Per Member Per Month'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.

Accumulated Other Comprehensive (Income) Loss and Regulatory Asset/ (Liability)


The amount recognized in Accumulated Other Comprehensive Income after applying FAS 158 is shown in the Balance Sheet as Regulatory Asset – Retirement Plan and is computed as follows:


 

 

 

Year Ending December 31,

 

 

 

2008

2007

Amount recognized in Accumulated Other

 

 

 

Comprehensive Income After Applying FAS 158:

 

 

 

 

Relating to Pension

 

$      12,954,867

$         (186,747)

 

Deferred Tax relating to Pension

 

(974,983)

14,258

 

Relating to Post Retirement Medical

 

(524,225)

(517,333)

 

Deferred Tax relating to Post Retirement Medical

 

39,453

38,549

 

Total Amounts Recognized in Accumulated

 

 

 

       Other Comprehensive Income After Applying FAS 158

 

$      11,495,112

$         (651,273)

 

 

 

 

 

 

Allocated portion to regulated segments,

 

 

 

 

   shown as Regulatory Asset (Liability)-Retirement Plan

$        9,944,514

$         (563,747)

 

Allocated portion to non-regulated segments,

 

 

 

 

   shown as Other Comprehensive (Income)/Loss

 

2,486,128

(140,333)

 

Deferred Tax

 

(935,530)

52,807

 

Other Comprehensive (Income) Loss net of Deferred Tax

 

1,550,598

(87,526)

 

Total for regulated and non-regulated segments

 

$      11,495,112

$          (651,273)


D.

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 $2 million in 2008, $1.8 million in 2007 and $1.7 million in 2006 excluding administrative and stop-loss insurance.


E.

401K Plan

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


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.


The Company plans to replace the current pension plan with the 401K match discussed above at the end of 2009 for all remaining employees.


F.

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.


14.

Covenants

We have historically met all our line of credit and fuel supplier covenants. As of December 2008 we were in violation of a covenant regarding our total liabilities to tangible net worth ratio included in one of our supply agreements with a fuel provider. The violation was caused primarily by a significant increase in our pension liability.  Failure to meet this covenant would have required us to provide a one year irrevocable letter of credit for $3.3 million; however, we received a 30 day time extension to March 27, 2009 to meet this covenant ratio. On March 20, 2009, we calculated the covenant ratio, as of February 28, 2009, and are now are in compliance with this covenant. We plan to notify the fuel provider before March 27, 2009 of our compliance.  At this time management does not anticipate any further covenant violations.


Our line of credit contains a similar covenant ratio. The Company is in compliance with all covenants on our line of credit and other fuel supply agreements at December 31, 2008. Management is continuing to take steps to comply with all covenants going forward, but there can be no assurance that further deterioration of the market or the economy will not occur and give rise to a violation.  


15.

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 2008, 2007 and 2006 is summarized as follows:


(Dollars in thousands)

 

2008

 

2007

 

2006

Revenues

 

 

 

 

 

 

Natural gas

$

72,624 

64,850 

71,139 

Electric

 

78,655 

 

55,521 

 

48,527 

Propane gas

 

17,269 

 

16,171 

 

15,115 

Consolidated

$

168,548 

136,542 

134,781 

Operating income, excluding income tax

 

 

 

 

 

 

Natural gas

$

3,563 

4,647 

6,118 

Electric

 

4,205 

 

2,653 

 

3,053 

Propane gas

 

1,341 

 

1,521 

 

1,006 

Consolidated

$

9,109 

8,821 

10,177 

Identifiable assets

 

 

 

 

 

 

Natural gas

$

101,920 

99,295 

93,689 

Electric

 

58,220 

 

54,202 

 

52,251 

Propane gas

 

18,534 

 

19,371 

 

19,239 

Common

 

30,257 

 

19,476 

 

16,055 

Consolidated

$

208,931 

192,344 

181,234 

Depreciation and amortization

 

 

 

 

 

 

Natural gas

$

4,569 

4,374 

4,095 

Electric

 

3,202 

 

2,714 

 

2,610 

Propane gas

 

824 

 

898 

 

720 

Common

 

317 

 

300 

 

317 

Consolidated

$

8,912 

8,286 

7,742 

Construction expenditures

 

 

 

 

 

 

Natural gas

$

6,017 

11,134 

7,643 

Electric

 

3,907 

 

4,387 

 

3,184 

Propane gas

 

1,041 

 

773 

 

1,885 

Common

 

262 

 

446 

 

404 

Consolidated

$

11,227 

16,740 

13,116 

Income tax expense

 

 

 

 

 

 

Natural gas

$

270 

730 

1,336 

Electric

 

929 

 

430 

 

546 

Propane gas

 

361 

 

272 

 

110 

Common

 

243 

 

265 

 

246 

Consolidated

$

1,803 

1,697 

2,238 



16.

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

2008

 

 

 

 

 

 

 

 

Revenues

$

45,030 

41,376 

41,934 

40,208 

Gross profit

$

14,118 

12,025 

11,863 

13,221 

Operating income

$

4,011 

1,142 

1,566 

2,390 

Earnings before income taxes

$

3,016 

60 

   644 

1,569 

Net Income

$

1,950 

81 

424 

1031 

Earnings per common share (basic and diluted)

$

 0.32 

0.01 

0.07 

0.17 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 





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, 2008 and 2007 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, 2008.  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, 2008 and 2007, and the results of its operation and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.




BDO Seidman, LLP

Certified Public Accountants

West Palm Beach, Florida

March 20, 2009



Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


None.


Item 9A(T).

Controls and Procedures


Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of December 31, 2008. Based on that evaluation, our CEO and CFO have concluded that, as of December 31, 2008, our disclosure controls and procedures were effective.


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, 2008. 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, 2008.


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, 2008 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 2009 Annual Meeting of Shareholders (the “2009 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 2009 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 Communications with Shareholders” in the 2009 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 2009 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 – 2008 Director Compensation”, "Executive Compensation", and “Compensation Committee Interlocks and Insider Participation” in the 2009 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 2009 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 2009 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 2009 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 2008 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 2008 Annual Report to Shareholders:


Allowance for Doubtful Accounts


(3)

Exhibits


3.1

Restated Articles of Incorporation (Incorporated herein by reference as Exhibit 3.1 on FPU’s Form 8-K filed November 10, 2008)


3.2

Restated By-Laws effective as of November 7, 2008 (Incorporated herein by reference as Exhibit 3.2 on FPU’s Form 8-k filed November 10, 2008)


3.3

Amendment to Articles of Incorporation increasing the number of authorized shares of common stock, $1.50 par value per share, from 6,000,000 to 10,000,000 shares. (Incorporated herein by reference as Exhibit 3.3 on FPU’s Form 10-Q for the quarter ended on June 30, 2008)


4.1

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)


4.2

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)


4.3

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)

10.1

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)


10.2

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)


10.3

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)


10.4

Amended Security Agreement and Promissory Note between FPU and Bank of America dated March 21, 2008.  (Incorporated by reference as Exhibit 10.1 on FPU’s Form 10-Q for first quarter ending March 31, 2008.)


10.5

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)


10.6

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)


10.7

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)


10.8

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)


10.9

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)


10.10

Amended and restated Electric Service Contract by and between JEA and Florida Public Utilities Company dated November 6, 2008. (Incorporated by reference as Exhibit 10.1 to our Form 8-K filed November 12, 2008)


10.11

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)


10.12*

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)


10.13

Network Operating Agreement between FPU and Southern Company Services, Inc. for the transmission of power purchased from Gulf Power Company, dated June 9, 2008. (Incorporated by reference as Exhibit 10.3 on FPU’s Form 10-Q for the quarter ended June 30, 2008)


10.14

Network Integration Transmission Service Agreement between FPU and Southern Company Services, Inc. for the transmission of power purchased from Gulf Power Company, dated June 9, 2008. (Incorporated by reference as Exhibit 10.4 on FPU’s Form 10-Q for the quarter ended June 30, 2008)


10.15

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)


10.16

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)


10.17

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)


10.18

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)


10.19

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)


10.20#

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)


10.21

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)


10.22

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)


10.23

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)

10.24

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)


10.25

Agreement with Chevron Natural Gas dated December 13, 2007. (Incorporated by reference as Exhibit 10(x) on FPU’s Form 10-K for the year ended December 31, 2007)


10.26

Amendment to physical sale Agreement with Inergy Propane, LLC dated October 31, 2007 (Incorporated by reference as Exhibit 10(y) on FPU’s Form 10-K for the year ended December 31, 2007)


10.27*

Physical Sale Agreement between FPU and Inergy Propane, LLC dated May 1, 2008 (Incorporated by reference as Exhibit 10.2 on FPU’s Form 10-Q for the quarter ended June 30, 2008)


10.28*

Physical Agreement between FPU and Inergy Propane, LLC dated as of February 18, 2009, relating to March and April 2009 purchases


10.29*

Physical Agreement between FPU and Inergy Propane, LLC dated as of February 18, 2009, relating to May 2009 through February 2010 purchases


10.30

Agreement with Crosstex Gulf Coast Marketing LTD dated December 14, 2007. (Incorporated by reference as Exhibit 10(z) on FPU’s Form 10-K for the year ended December 31, 2007)


10.31#

Employment Agreement between the Company and John T. English dated August 21, 2008 (Incorporated by reference as Exhibit 10.1 on FPU’s Form 8-K filed August 21, 2008)


10.32#

Employment Agreement between the Company and Charles L. Stein dated August 21, 2008 (Incorporated by reference as Exhibit 10.2 on FPU’s Form 8-K filed August 21, 2008)


10.33#

Employment Agreement between the Company and George M. Bachman dated August 21, 2008 (Incorporated by reference as Exhibit 10.3 on FPU’s Form 8-K filed August 21, 2008)


10.34#

Summary of Annual Executive Officers’ Incentive Plan


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

Consent of Independent Registered Public Accounting Firm - 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.

*

This exhibit contains terms for which confidential treatment has been granted or requested.



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 20, 2009


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 20, 2009

John T. English

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

Director (Principal Executive Officer)


/s/ George M. Bachman

Date:  March 20, 2009

George M Bachman, Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)


/s/ Ellen Terry Benoit

Date:  March 20, 2009

Ellen Terry Benoit, Director


/s/ Richard C. Hitchins

Date:  March 20, 2009

Richard C. Hitchins, Director


/s/ Dennis S. Hudson III

Date:  March 20, 2009

Dennis S. Hudson III, Director


/s/ Paul L. Maddock, Jr.

Date:  March 20, 2009

Paul L. Maddock, Jr., Director


/s/ Troy W. Maschmeyer, Jr.

Date:  March 20, 2009

Troy W. Maschmeyer, Jr., Director








FLORIDA PUBLIC UTILITIES COMPANY

EXHIBIT INDEX


Item Number

10.28*

Physical Agreement between FPU and Inergy Propane, LLC dated as of February 18, 2009, relating to March and April 2009 purchases


10.29*

Physical Agreement between FPU and Inergy Propane, LLC dated as of February 18, 2009, relating to May 2009 through February 2010 purchases


10.34#

Summary of Annual Executive Officers’ Incentive Plan

23

Consent of Independent Registered Public Accounting Firm - 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)



*

[  ]   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

 

NYSE Amex



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.   [  ]


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

[  ]

Smaller reporting company

[X]

(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 30, 2008, 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 NYSE Amex) was approximately $69,085,000.


On March 2, 2009, 6,116,505 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 12, 2009 Annual Meeting of Shareholders are incorporated by reference in Part III hereof.



TABLE OF CONTENTS


PART I

Item 1

Business

Item 1A

Risk Factors

Item 1B

Unresolved Staff Comments

Item 2

Properties

Item 3

Legal Proceedings

Item 4

Submission of Matters to a Vote of Security Holders Executive Officers of the Registrant


PART II

Item 5

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 6

Selected Financial Data

Item 7

Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 7A

Quantitative and Qualitative Disclosures about Market Risk

Item 8

Financial Statements and Supplementary Data

Item 9

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A

Controls and Procedures


PART III

Item 10

Directors, Executive Officers and Corporate Governance

Item 11

Executive Compensation

Item 12

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

Item 13

Certain Relationships and Related Transactions, and Director Independence

Item 14

Principal Accountant Fees and Services


PART IV

Item 15

Exhibits, Financial Statement Schedules

Signatures

Exhibit Index


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 12,000 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 Palm Beach, West Palm Beach, Royal Palm Beach, Palm Beach Gardens, North Palm Beach, Jupiter, Riviera Beach, Lake Worth, 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, Flagler County, parts of Lake County and Orange County and other areas near these cities and counties.  Our previous separate West Florida Division, which provides propane gas to customers in Dunnellon, Inglis, Crystal River, Inverness, Brooksville and other areas near these cities, is now consolidated with our Central Florida Division.

(3)

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

(4)

Northeast Florida Division - provides electricity to Fernandina Beach/Amelia Island in Nassau County and propane gas to customers in Fernandina Beach, Jacksonville, Callahan, Yulee and other areas within Nassau, Duval and Clay counties.


Business Environment

The historic growth that had 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 a reliable and environmentally friendly alternative energy source in the event of a power outage. During 2008, the cost of natural gas and propane gas was extremely volatile due to changes in the cost of crude oil and the economic downturn.


Historically, our cost of fuel in the electric segment had not been impacted by market fluctuations due to favorable long-term fixed price contracts for purchasing electricity. However, our long-term contracts terminated at the end of 2006 for our Northeast division and at the end of 2007 for our Northwest division. The new contracts in place have pricing closer to current market prices. As a result of these increased fuel costs, our cost of electricity sold significantly increased.  This does not directly impact our income from operations as increased fuel costs are passed through to the customers; however, this likely contributed to customers using less electricity which in turn decreased 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 15 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 to transport our natural gas supplies through its pipeline into peninsular Florida. Florida Gas Transmission 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 Florida Gas Transmission. We pass all fuel costs on to our customers at cost.  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 cost of gas.


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 and thus lower our sales.


The natural gas industry has not been deregulated in the state of Florida. Our current portfolio of natural gas customers is reasonably diverse, with the largest customer using natural gas for the generation of electricity.  We were 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).  The cost of electricity is passed through to customers at cost.


During 2006 we completed negotiations with JEA and executed final contracts for the supply of electricity in our Northeast division beginning on January 1, 2007 and our Northwest division from Gulf Power Company beginning on January 1, 2008. Both these contracts expire on December 31, 2017. 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.


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 in 2008.


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. No propane gas customer represented more than ten percent of our 2008 propane revenues.


Strategy

Our strategy is to leverage our expertise in the natural gas, electric and propane gas distribution business to assist us in consistently meeting our customers’ expectations. Our core focus for natural gas is customer retention and improving our market share in areas that are either on or near our natural gas mains. For propane, we are concentrating on retention, load growth and increasing market share in existing communities known to have high concentrations of propane gas users. In electric, our strategy is to educate our customers as to how our energy conservation programs may benefit them long term and ultimately reduce electric usage. For all areas of operations, we continue to strive and focus on excellent customer satisfaction and service.

 

Competition

We do not face substantial competition in our electric divisions.  This is because no competitor can 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 regulatory 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, 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 but not guarantee 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 including pension and medical expenses 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.  The FPSC is likely to grant rate increases to offset increased expenditures necessary for business operations; however, the process can take up to eight months from the filing date.


The FPSC approved an annual electric final rate increase of approximately $3.9 million effective May 22, 2008.  Interim rate relief for partial recovery of the increased expenditures was approved by the FPSC on October 23, 2007. Interim rates were effective in November of 2007 up until May 22, 2008, the date our final rates went into effect.  The increase produced additional annual revenues of approximately $800,000.


We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase in our natural gas segment. This request included recovery of increased expenses and some capital expenditures since our last rate proceeding in 2004. Finalization of this request and approval, if any, of a natural gas base rate increase would not occur until mid 2009. Interim rates which are expected to produce additional annual revenues of approximately $1 million went into effect for meter readings on and after March 12, 2009. Interim rates are collected subject to refund, pending the resolution of the issues and the outcome of the final rate proceeding.


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, the United States Environmental Protection Agency 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 Florida Department of Environmental Protection and the Environmental Protection Agency 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.


The City of Marianna is currently reviewing the franchise agreement with the Company that is up for renewal in 2010. The City has hired a Consultant to review the feasibility of purchasing the portion of our electric system that is within the city limits. If the City elects to purchase the Marianna portion of the distribution system, it would be required to pay the fair market value, and would need to invest in the infrastructure to operate this limited facility. If the franchise is not renewed and the City purchases this portion of our electric system, the Company would have a gain in the year of the acquisition.  Ongoing financial results would be negatively impacted from the loss of this operating area within our electric operations. At this time we do not believe the City will find it prudent and we expect the Marianna Franchise will be renewed.


Seasonality

The effects of seasonal weather conditions and the migration of winter residents and tourists to Florida during the winter season impact our income.


Employees

As of February 28, 2009, we employed 348 employees, including 10 part-time and 8 temporary employees. Of these employees, 169 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 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.


The FPSC regulates many aspects of our natural gas and electric operating segments, including the retail rates we 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.


We filed a request with the FPSC in the fourth quarter of 2008 for a base rate increase of approximately $9.9 million annually in our natural gas segment. Interim rate relief was approved by the FPSC on February 10, 2009 for partial recovery of the increased expenditures. If the FPSC approves partial recovery instead of full recovery of the requested rate increase, the impact to our 2009 and future net operating income in our natural gas segment would be lower than anticipated.


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, 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 materially 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 alternative energy competitive forces for several years. We receive our supply of natural gas at thirteen city gate stations connected to an interstate pipeline system owned by Florida Gas Transmission, 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 but we are not utilizing that pipeline at this time.


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 and faces 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.


Florida Gas Transmission’s pipeline system transports all of our natural gas.  Florida Gas Transmission is owned by Citrus Corporation, which is jointly owned by CCE Holdings, LLC, a joint venture of Southern Union Company and GE Commercial Finance Energy Financial Services.  Our ability to receive a normal supply of natural gas could adversely affect earnings if there is an interruption in Florida Gas Transmission’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. Fuel costs could also increase as a result of economic conditions. Consumers reduce energy consumption as costs go up and the economy worsens. This adversely affects our unit sales. A further 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. Further construction and housing market declines can negatively impact our customer growth and customer retention. Loss of commercial customers due to bankruptcies and business closings which have been increasing in this declining economy adversely affects our unit sales.


As the downturn in the economy affects consumer spending, tourism in Florida may be adversely affected. If tourism is down, then the demand for the energy we supply is reduced. Changes in political climate, including terrorist activities, could further negatively impact our performance.


In addition, deterioration in the financial condition of our customers as a result of the economy could cause significant increase in our bad debt expense and related write-offs to our receivables, which would negatively impact our profitability.


We are vulnerable to the stock market and the impact to our pension liability.


The recent decline in the stock market and the impact to our pension liability and related contributions has been significant. Additional declines in the stock market and valuation of stocks could further impact our pension liability and contributions.


We are vulnerable to covenant violations which could impact our short-term line of credit or our ability to obtain additional short-term funding.


The general economic conditions and credit climate could impact our ability to obtain short-term debt financing as a result of potential violation of current covenants. The pension liability has increased significantly as a result of the continued decline in the stock market. As a result, we are approaching ratio limitations related to our current short-term debt covenants that if violated, could cause the bank to request immediate payment of our line of credit balance, or limit our ability to borrow as needed. There can be no assurance that we would be able to repay the line of credit without securing additional financing, which may not be available on reasonable terms or at all.